System and process for the manufacture of hydrocarbons and upgraded coal by catalytic mild temperature pyrolysis of coal

ABSTRACT

A process for upgrading a solid carbonaceous material includes heating the solid carbonaceous material in the presence of a catalyst under partial pyrolysis conditions and obtaining an upgraded solid carbonaceous product, a gaseous product, and a spent catalyst.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a U.S. National Stage application from International (PCT) Application No. PCT/US2015/032252, filed on May 22, 2015, which claims the benefit of and priority to U.S. Provisional Patent Application No. 62/002,674, filed on May 23, 2014. The foregoing applications are incorporated by reference herein in their entireties.

FIELD

The present technology relates generally to a system and process for the conversion of solid carbonaceous materials to a set of usable products. More specifically, the technology relates to a system and process that utilizes a catalyst to convert the solid carbonaceous materials into a gaseous product, a liquid product, and/or an upgraded solid product (e.g., an upgraded solid carbonaceous product).

BACKGROUND

Given the uneven global distribution of crude oil reserves and finite nature of crude oil reserves in the spotlight, there is an ever-increasing need to develop alternative production technologies based on alternative feedstocks (e.g., coal, biomass, etc.). In the past decades, coal to liquid (CTL) technologies have achieved some progress. The most technically defined route for producing hydrocarbon liquids involves gasification, generally involving relatively high temperature steam and oxygen co-feeds to produce syngas. Significant cleaning of the resulting syngas is required prior to further conversion to a methanol intermediate, or for direct synthesis, and thus, generally involves an integrated, multistep approach, gasification-based facility, which is typically costly to build and operate. Another route for producing hydrocarbon liquids from coal is the so-called direct coal liquefaction (DCL) route which involves direct liquefaction via high pressure treatment of coal solids with pure hydrogen. Even though the DCL process typically utilizes catalysts, the desired hydrocarbon product selectivity out of the catalytic reactor is low and further processing is required. In other words, the DCL process cannot be tailored to produce specific hydrocarbon products, and in particular, lower molecular weight hydrocarbons. Therefore, the DCL product stream requires significant additional chemical upgrading steps resulting in facilities which are also cost intensive to build and operate. Another conventional route for producing hydrocarbon liquids from coal is through mild temperature gasification or pyrolysis. The resulting liquid product stream from conventional pyrolysis contains relatively high concentrations of high molecular weight tars that require considerable upgrading, typically via catalytic hydrogenation. The overall pyrolysis product selectivity to non-hetero-atom containing C₁˜C₁₂ hydrocarbon products is relatively low.

SUMMARY

In one aspect, a process for upgrading a solid carbonaceous material is provided. The process includes heating the solid carbonaceous material in the presence of a catalyst under partial pyrolysis conditions, and obtaining an upgraded solid carbonaceous product, a gaseous product, and a spent catalyst. One non-limiting example of solid carbonaceous material is coal and, therefore, one non-limiting example of upgraded solid carbonaceous product is an upgraded coal product.

In another aspect, a process for converting a solid carbonaceous material in a beneficiation system into an upgraded solid carbonaceous product is provided. The process includes introducing the solid carbonaceous material and a catalyst into a pyrolysis reactor to produce a gaseous product stream and a solid product stream, where the solid product stream includes the upgraded solid carbonaceous product. The process further includes recovering the gaseous product stream from the reactor, and recovering the solid product stream from the reactor. One non-limiting example of solid carbonaceous material is coal and, therefore, one non-limiting example of upgraded solid carbonaceous product is an upgraded coal product.

In another aspect, a process for converting a biomass in a beneficiation system into an upgraded solid product is provided. The process includes introducing the biomass and a catalyst into a pyrolysis reactor to produce a gaseous product stream and an upgraded solid product stream, where the solid product stream includes spent catalyst and the upgraded solid product. The process further includes separating the upgraded solid product and the spent catalyst, and transferring the separated spent catalyst to a regenerator that removes at least a portion of any unpyrolyzed coal, coke, and other carbonaceous material from the spent catalyst. A weight of ash retained in the upgraded solid product is at least 60 weight percent of ash in the biomass introduced into the pyrolysis reactor. The process further includes transferring the gaseous product stream to a separator that produces a liquid product and a gaseous product.

The pyrolysis reactor may operate from about 300° C. to about 1,100° C. In some embodiments, this may include from about 350° C. to about 850° C., or from about 400° C. to about 700° C. The carbonaceous material may have a residence time of about 0.01 second to about 5 hours. In some embodiments, the residence time is from about 0.1 second to about 1 minute. The catalyst loading for the pyrolysis reactor may be from about 0 (zero) to about 100 g of catalyst/g of carbonaceous feed material. In some embodiments the catalyst loading may be from about 0.05 g catalyst/g feed material to about 10 g catalyst/g feed material. The heating rate of the carbonaceous material in the reactor may be from about 0.1° C./sec to about 1000° C./sec.

In at least one embodiment, the starting carbonaceous material enters directly into the pyrolysis reactor. In other embodiments, prior to entering the pyrolysis reactor, the carbonaceous material may be pre-processed, such as, for example, via a pulverizer, a dryer, and/or any other suitable pre-processer or pre-process discussed below.

In at least one embodiment, the starting carbonaceous material is introduced into a pyrolysis reactor with a catalyst, which can be mixed with the carbonaceous material before entering the reactor, or within the reactor. The solid stream exiting the reactor includes spent catalyst and the upgraded solid product. The solid stream is then separated into a first solid stream containing predominantly the upgraded solid product, which may be sent for further processing or combustion as an upgraded solids fuel, and a second solid stream containing predominantly spent catalyst, which may be sent to a regeneration reactor before being recycled back into the pyrolysis reactor. For example, the particle size distributions of upgraded carbonaceous material and the catalyst can be intentionally different, allowing for appropriate classification technology to separate the two solids by differences in particle size, weight and/or density. Other technologies may be used as an alternative or in conjunction with the classifier, which include but are not limited to other classifier technologies, electrostatic separation, electrodynamic separation, triboelectric separation and/or magnetic separation. High gradient magnetic separators, which use high magnetic gradients to attract weakly paramagnetic, or very fine ferromagnetic, particles, may be utilized with the systems of this application. Open gradient magnetic separators, which segregate falling particles in a falling stream according to their magnetic characteristics, may be utilized with the systems described herein. Electrodynamic separators, in which feed particles become charged from ion bombardment and are pinned to a rotating drum, may be utilized with the systems described herein. In such electrodynamic separators, particles with higher conductivity tend to lose their charge faster while those particles with less conductivity (i.e., more insulated particles) tend to stay attached, leading to separation of the particles. Triboelectric separators, which charge particles through friction, then pass the particles through an electric field to be deflected according to the sign and magnitude of their charge.

According to another embodiment, the solids (e.g., the catalyst and carbonaceous material) may remain separated within the pyrolysis reactor. One example is where the catalyst is immobilized in the reactor, such as where the catalyst is immobilized by plating on the walls of the reactor, while the carbonaceous material enters and exits the pyrolysis reactor. In such a system, the need for solid-solid separation of catalyst from the upgraded solid product outside the reactor is essentially eliminated, since the solids remain separated within the reactor.

According to another embodiment, the solids are commingled and then separated within the reactor. One such example is where the reactor is in the form a fluidized bed, in which the catalyst and starting carbonaceous material are mixed (e.g., commingled) inside (or before entering) the reactor. After the carbonaceous material has intimately interacted with the catalyst, the mixed solid product stream is passed through a solid-solid separator located inside the reactor (e.g., an internal classifier) to separate the catalyst and carbonaceous material. In such a system, the need for solid-solid separation of catalyst from product solids outside the reactor is essentially eliminated, since separation occurs within the reactor.

The gaseous product stream may be transferred to one or more separation units, such as to condense a liquid product stream and separate the products into desired fractions. One such example of a separation unit is an acid gas removal system, wherein sulfur-containing chemicals and most of the carbon dioxide are removed, each into high purity (e.g., concentrated) streams. Other separators may be used, and other compounds may be removed, such as hydrogen cyanide (HCN) or ammonia (NH₃). The highly concentrated stream of carbon dioxide can be captured for sequestration or used in the plant or pipelined for use externally, such as for enhanced oil recovery. The highly concentrated stream of sulfur containing compounds can be processed for landfilling, to produce useable solid sulfur, or to produce a useable sulfur-containing compound, such as sulfuric acid.

One gaseous product stream may include one or more non-condensable gases or chemicals, such as, for example, methane, ethane, ethylene, carbon monoxide, carbon dioxide, and/or hydrogen. The non-condensable stream may also be processed further to produce syngas for production of other chemical products, such as, but not limited to, methanol, mixed alcohols and/or Fischer Tropsch products. This non-condensable stream may be used as fuel in the process, such as to provide heat for the process or other unit operations in the plant. For example, it may be beneficial to pass a gaseous product (e.g., methane, ethylene, ethane, hydrogen, etc.) through the pyrolyzer as a recycle gas or a second pass stream. The recycled gaseous product may provide additional heat and/or hydrogen (since coal is generally low in hydrogen) into the reactor. The liquid stream can be captured as synthetic crude oil, or separated further to extract useable hydrocarbon chemicals into two or more chemical streams.

In addition, it may be advantageous to introduce fuel gases into the pyrolyzer from an external source. For example, natural gas and/or natural gas liquids (e.g., propane, propene, butane, butene, isobutane, isobutene, etc.) may be added from external sources. These added fuel gases would serve the dual purposes of providing fluidization gases and increasing the yield of useful fuels. This would be particularly beneficial if the facility (e.g., plant) were near so-called “stranded gas” reserves where such components are often disposed of by flare. This mixture of natural gas, natural gas liquids, and other condensable hydrocarbons are often referred to as “wet gas”. For purposes of this patent, “wet gas” will be understood to be a mixture of natural gas, natural gas liquids, and other condensable hydrocarbons.

Such co-production may advantageously provide synergistic benefits. The presence of free radicals in the coal and higher hydrocarbons in the process will catalyze the pyrolysis of these fuel gases effectively carrying out a gas-to-liquids conversion in parallel with the coal beneficiation. This is of particular benefit to methane pyrolysis, which is extremely difficult to carry out without the presence of free radicals. Free radicals increase the per-pass pyrolysis conversion of methane to higher fuels from <1% to about 10%.

Another embodiment relates to a system and a process for converting a carbonaceous material into multiple usable products utilizing a catalyst. The carbonaceous material may include a coal (e.g., a low-grade coal), a biomass, a waste, bitumen, or a combination of any two or more carbonaceous materials. The carbonaceous raw material may be pre-processed prior to entering the pyrolysis reactor, such as by pulverization to resize (e.g., grind, reduce, etc.) the particles of raw, carbonaceous material and/or drying to reduce the moisture content in the raw, carbonaceous material.

The pyrolysis reactor may be configured as a moving bed, an entrained flow bed, a fluidized bed, or any suitable reactor where all solid material (e.g., carbonaceous material, catalyst, etc.) moves through the reactor. Alternatively, the pyrolysis reactor may be configured as a fixed bed or any suitable system where the catalyst remains stationary during the reaction with the carbonaceous material that enters and exits the reactor.

The solid material exiting the pyrolysis reactor, including the upgraded solid product and the spent catalyst, are separated into at least two solid streams (i.e. a solid-solid separation) including a first stream of predominantly upgraded solid product and a second stream of predominantly spent catalyst (e.g., a catalyst stream), except for the immobilized catalyst reactor where only a single solid stream of upgraded solid product exits the reactor. The solid-solid separation of the solid material may be performed partially or fully in situ within the pyrolysis reactor and/or after exiting the reactor. In other words, the solid material exiting the pyrolysis reactor may be separated internally to the reactor or externally. The solid-solid separation of the first and second streams can be performed using a classifier, or similar technology, such as where the solids are separated based on particle size, mass, and/or density, electrostatic separation techniques, or magnetic separation techniques.

The catalyst stream including spent catalyst may be sent to a regenerator (e.g., a regeneration unit) where the spent catalyst is regenerated by combusting any residual (e.g., remaining, left-over, etc.) carbonaceous material to produce mainly regenerated catalyst and ash residue of the combusted carbonaceous material. A portion of the spent catalyst may be sent back to the reactor without being regenerated, or may be discarded. An oxygen-carrying gas, such as air, may be introduced into the regeneration reactor to regenerate the spent catalyst and combust the remaining carbonaceous material in the regeneration reactor. A gas stream exiting from the regenerator may include resultant flue gas. Part, or all, of the flue gas exiting the regenerator may be utilized to provide heat directly or indirectly to the pyrolysis reactor, the dryer, and/or another element of the system. Some, or all, of the gas exiting the regenerator may be used to transport the regenerated catalyst to the pyrolysis reactor.

The non-solid product exiting from the pyrolysis reactor may be separated into at least two streams (e.g., a gaseous product stream and a liquid product stream). The liquid product stream may be processed further through chemical upgrading, by separation processes, or collected as synthetic crude product stream, which can be refined into constituents (e.g., C₅-C₁₂) or hydrocarbons, including aromatics. The gaseous product stream may be processed further through chemical upgrading, by separation processes into multiple useable process streams including a non-condensable stream, or used within the plant, such as gaseous fuel or collected as another product stream.

Some, or all, of the non-condensable gas product stream may be burned for heating value. The heat may be used in the pre-processing of the carbonaceous raw material, in the pyrolysis reactor, or elsewhere in the plant.

Some, or all, of the gaseous product stream may be introduced into an acid gas removal system, wherein the sulfur-carrying compounds and/or nitrogen-containing compounds (e.g., ammonia and hydrogen cyanide) and/or the carbon dioxide are/is separated. The sulfur-carrying compounds can be further processed and sold as useable sulfur-containing compounds, such as, but not limited to, elemental sulfur and/or sulfuric acid. The carbon dioxide stream can be sequestered, or used as a useable product such as, but not limited to, the purpose of enhanced oil recovery.

In at least one embodiment, a beneficiation system for converting coal into an upgraded coal product is provided, and the beneficiation system includes a pyrolysis reactor, a first separator, a regenerator, and a second separator. The pyrolysis reactor has an inlet that receives the coal and a catalyst. The pyrolysis reactor produces a gaseous product stream and an upgraded coal product stream, which comprises spent catalyst and the upgraded coal product, from the coal and catalyst. The first separator separates the upgraded coal product and the spent catalyst. The regenerator has an inlet that receives the separated spent catalyst from the first separator. The regenerator removes at least a portion of any unpyrolyzed coal, coke, and other carbonaceous material from the spent catalyst. The second separator has an inlet that receives the gaseous product stream from the pyrolysis reactor, and the second separator produces a liquid product and a gaseous product from the gaseous product stream. A weight of ash retained in the upgraded coal product may be at least 60 weight percent of ash in the coal introduced into the pyrolysis reactor.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an illustrative embodiment of a system and process flow for converting a carbonaceous material into one or more usable products.

FIG. 2 is a schematic diagram of another illustrative embodiment of a system and process flow for converting a carbonaceous material into one or more usable products.

FIG. 3 is a schematic diagram of another illustrative embodiment of a system and process flow for converting a carbonaceous material into one or more usable products.

FIG. 4 is a schematic diagram of yet another illustrative embodiment of a system and process flow for converting a carbonaceous material into one or more usable products.

FIG. 5 is a graph comparing the yield of various products produced through an experimental system using a catalyst vs. sand.

FIG. 6 is another graph comparing the yield of various products produced through an experimental system using a catalyst vs. sand.

FIG. 7 is yet another graph comparing the yield of various products produced through an experimental system using a catalyst vs. sand.

FIG. 8 is a cross-sectional view of an exemplary embodiment of a pyrolysis reactor configured to provide solid-solid separation.

FIG. 9 is a perspective view of a portion of the pyrolysis reactor of FIG. 8.

FIG. 10 is another perspective view of a portion of the pyrolysis reactor of FIG. 8.

FIG. 11 is a partial cross-sectional/perspective view of another exemplary embodiment of a pyrolysis reactor configured to provide solid-solid separation.

FIG. 12 is a schematic view of another exemplary embodiment of a pyrolysis reactor configured to provide solid-solid separation.

DETAILED DESCRIPTION

Prior to discussing the various embodiments disclosed in this application, several terms used in this application will be defined and discussed in detail for clarification. The term “solid carbonaceous material” (e.g., SCM, carbonaceous material or CM) is a material that is solid at standard temperature and pressure (25° C., 1 bar absolute pressure) that includes and/or yields carbon and/or a hydrocarbon. Non-limiting examples of solid carbonaceous material include coal, peat, lignite, biomass, coke, semi-coke, petroleum coke, tars, or asphalt. The term “carbonaceous material” refers to “solid carbonaceous material,” unless stated otherwise. The term “volatile matter,” the term “moisture” (e.g., water), the term “fixed carbon,” and the term “ash content” of solid carbonaceous material shall mean the values that are determined by proximate analysis as defined in ASTM 3172. The term “upgraded solid carbonaceous product” (e.g., upgraded solid carbonaceous material) is any material having one or more of the following nine characteristics relative to the starting carbonaceous material. First, a higher heating value (abbreviated in this application as “HHV”) as defined by ASTM D5865 method (as received basis, e.g., including moisture, ash, and other non-combustible material). Second, a higher heating value by ASTM D5865 method (dry basis, where moisture is determined by ASTM 3172 method). Third, a higher heating value by ASTM D5865 method (dry, ash-free basis where moisture and ash are determined by ASTM 3172 method). Fourth, a lower volatile matter by ASTM D3172 method. Fifth, a lower overall sulfur content by ASTM D4239 method. Sixth, a lower organic sulfur content by ASTM D2492 method. Seventh, a lower sulfate content by ASTM D2492 method. Eighth, a lower pyritic sulfur content by ASTM D2492 method. Ninth, a lower moisture by ASTM D3172 method. Further, the term “upgraded” used with any specific material (e.g., coal, biomass, etc.) shall also be defined as provided above. It shall be understood that the term “upgraded carbonaceous product” implies “upgraded solid carbonaceous product,” unless stated otherwise.

When referring to “retention” and other comparable terms (e.g., retained, retaining), it is noted that the processes, as disclosed in this application, fundamentally transform a feedstock material including a solid carbonaceous material into a solid carbonaceous product and, therefore, it is often more accurate to consider how much of each component in the solid carbonaceous feed material is retained in the solid carbonaceous product, rather than the absolute weight fraction of the components in the solid carbonaceous product. Accordingly, the term “retention” denotes a portion of a given component in the solid carbonaceous feedstock that is contained in the upgraded carbonaceous product. For example, the retention of component X, may be discussed herein (e.g., in a table) as kg of component X contained in upgraded carbonaceous product divided by 100 kg of component X contained in solid carbonaceous feed material. Thus, it may be considered as an unconverted weight fraction. For example, if 100 kg of coal containing 3% by weight sulfur is converted to 60 kg of upgraded coal containing 3% weight sulfur, the retention of sulfur is 60 kg per 100 kg of sulfur feed, because the coal feed contained 3 kg of sulfur whereas the upgraded coal product contained 1.8 kg of sulfur. The term “de-asher” is any device which reduces the ash content in a solid carbonaceous material.

One objective of the pyrolysis of solid carbonaceous materials is to form higher value fuels and organic chemicals. As such, it is desirable to maximize the conversion of organic components in the feed solid carbonaceous materials to the desired end states. However, as a practical matter, nearly all naturally occurring (e.g., biomass and fossil-based) solid carbonaceous feedstocks contain ash—inorganic material bound into the solid carbonaceous material. This ash is extremely stable and in most chemical transformations of solid carbonaceous material (e.g., combustion, gasification, pyrolysis), as the solid carbonaceous material is converted ash becomes liberated from the solid carbonaceous material. For example, in a coal-fired steam generation station, this ash can be manifested as a slag or fly-ash co-product.

This liberated ash (e.g., “free ash”) has been particularly problematic in catalytic transformations. Catalytic materials are often highly designed for a particular and/or controlled selectivity and activity. This is done by designing the catalyst's surface chemistry and morphology, including its porosity and structure. Ash interferes with all of these critical features. Inorganic ions in the ash can manipulate the surface chemistry of active sites, and ash fines can clog pores and change morphology in general. This leads to a number of adverse effects, several of which are discussed herein. First, reduced activity due to reduction in active and/or available surface area of the catalyst can lead to lower productivity of the reactor and lower yields of products. Second, poisoning can occur, requiring more frequent regeneration of the catalyst or in even worse, irreversible deactivation of the catalyst requiring replenishment of spent catalyst with new catalyst, leading to excessive waste and an uneconomical process. Third, reduced selectivity to desired products can occur. For example, selectivity to the desired light hydrocarbons and BTEX (defined below) is determined by the shape and surface activity of the catalyst. Changes in pore size will reduce the selectivity to these materials resulting in uncontrolled thermal pyrolysis. Fourth, an increase in undesired by-products can occur. Uncontrolled thermal pyrolysis, in the absence of a catalyst, results in many undesired materials, such as tars and heteroatom containing organics (such as phenol, which is toxic to humans and it is also a poison in many downstream refining operations).

Various tar fractions are known. For example, these include ammoniacal liquor (boiling range of about 100° C.), light oil (boiling range from 100° C. to about 170° C.) and potentially containing materials such as benzene, toluene, and xylenes, middle oil (boiling range from 170° C. to about 230° C. and potentially containing lower naphthalene fractions, heavy oil (boiling range from 230° C. to about 270° C. and potentially containing higher naphthalene fractions, green oil (boiling range from 270° C. to about 360° C. and potentially containing anthracene fractions, and the residual matter or “pitch” boiling at greater than 360° C.

Likewise Goodman et al. in their 1953 report entitled “Low Temperature Carbonization Assay of Coal in a Precision Laboratory Apparatus” used the Fischer Assay method to determine the main pyrolysis products from various types of coal in terms of product yield to char, tar, water, light oil and gas components. The light oil components are described as comprising varying amounts of benzene, toluene, xylenes and aromatic naphthas as well as small amounts of carbon disulfide, naphthalene, unsaturated hydrocarbons and saturated paraffin hydrocarbons. Based on the Fischer Assay method, the tars contain higher hydrocarbon constituents than light oil and the higher hydrocarbons are comprised mainly of hydrocarbon molecules with carbon atoms greater than about C₁₀, and boiling range above about 270° C. For purposes of this application, “tars” or “tar products” will be understood to be defined by this reference (i.e. hydrocarbons containing greater than 10 carbon atoms, and “non-tar light oils” or “non-tar light oil products” or simply “light oils” or “light oil products” will be understood to mean any hydrocarbon containing 10 or less than carbons. Typical uncatalyzed coal pyrolysis processes tend to yield a relatively low product weight ratio of light oil products to tar products, of much less than 1 in the range of about 0.08-0.25; whereas the processes of this application tend to yield a relatively high product weight ratio of light oil products to tar products, much greater than 1 in the range of about 5-1000 or greater. Also, a lower level of phenol (and other heteroatom-containing organics) is produced in the processes of this application. Without wishing to be bound by any particular theory or explanation, it appears that the presence of an active catalyst reduces the amount of phenol produced. For example, in FIG. 7, we can see that phenol levels are higher when sand (with little or no catalytic activity is used) compared to when a catalyst is used. Even more advantageous, the toluene levels produced increase when a catalyst is used (compared to when sand with little or no catalytic activity is used), such that an amount of toluene produced is greater than an amount of phenol produced on a weight basis (i.e., an amount of phenol produced is less than an amount of toluene produced on a weight basis). Also, in Table 2 (below) we can see that no phenol, or any other heteroatoms are observed in either example embodiment. In summary, without wishing to be bound by any theory or explanation, we believe that two principle factors contribute to this superior performance: 1) Presence of an active catalyst, and 2) sequestration (e.g., absorption and/or adsorption) of any tars produced in the upgraded CM product, which is most often subsequently and harmlessly burned as a fuel.

By our working explanation, presence of an active catalyst is important to the superior performance of this process. It is further believed that the processes of this application have superior operability and selectivity to desired products compared to previous processes, because much less ash is liberated compared to the previous processes. The reduction in ash liberation is believed to be in part due to intentionally limiting conversion levels of the feed solid carbonaceous material to retain a majority of ash in the product carbonaceous material. Thus, the catalyst is exposed to much less “free ash” than in the previous processes. It is a unique aspect (and somewhat counterintuitive) to intentionally limit the conversion of the solid carbonaceous feedstock. While the economics and productivity of converting as much of the solid carbonaceous feedstock may be compelling, it is believed that controlling conversion such that free ash production is minimized has a greater benefit than maximizing conversion of solid carbonaceous feedstock.

The term “non-condensable (fuel) gas” is any material, which cannot be condensed by pressurization into a liquid at 40° C. (i.e., a gas possessing a critical temperature below 40° C.). Further, a non-condensable gas that liberates heat upon reaction with air or oxygen is referred to herein as a “non-condensable fuel gas.”

The term “light condensable fuels,” such as liquefiable petroleum gases (LPGs), are gases that liberate heat upon reaction with air or oxygen and are condensable at 40° C. by pressurization, but do not bear more than 7 carbon atoms and are not aromatic.

The term “light hydrocarbons” is any material that is either a non-condensable fuel gas or a light condensable fuel, as defined herein.

The term “BTEX” denotes Benzene, toluene, ethylbenzene, m-xylene, p-xylene, or o-xylene.

The term “heteroatom containing organics” is any organic molecule bearing sulfur, oxygen, and/or nitrogen.

The term “higher hydrocarbons” is any hydrocarbon that is not a light hydrocarbon or BTEX, as defined herein.

The term “weighted hour space velocity” (WHSV) denotes the feed rate of substrate in weight per hour divided by weight of catalyst contained in the reactor. WHSV has the units of hr−1. As used herein, the weight hourly space velocity will be based on the hourly feed of coal by weight on a dry basis, and the weight of catalyst contained in the reactor. The weight of the catalyst will be determined in one of two ways. For reactors where no catalyst is removed or added (e.g., batch or fixed-bed reactors), the catalyst weight will be the initial weight of catalyst charged to the reactor. For reactors where some or all of the catalyst is elutriated from the reactor continuously (e.g., fluid-bed, hybrid, HERB, and riser reactors), the catalyst weight will be the steady state weight of the catalyst in the reactor, where steady state is defined by the input of fresh catalyst equaling the amount leaving (weight basis). This is often referred to as the catalyst “hold-up” and can be measured or estimated from known correlations for fluid-bed or riser reactors.

The term “catalyst activity” denotes the weight of volatile matter converted per catalyst weight over a given amount of time. The catalyst activity can be calculated by multiplying the WHSV by the fractional conversion of volatile matter in the reactor, or equivalently the WHSV*(1−the retention of volatile matter).

The term “fresh catalyst” denotes a catalyst that has never been exposed to reactants at reaction conditions, such as new catalyst received from a vendor.

The term “spent catalyst” denotes any catalyst that has less activity at the same reaction conditions (e.g., temperature, pressure, inlet flows) than the catalyst had when it was originally exposed to the process. This can be due to a number of reasons, several non-limiting examples of causes of catalyst deactivation are coking or carbonaceous material sorption or accumulation, metals (and ash) sorption or accumulation, attrition, morphological changes including changes in pore sizes, cation or anion substitution, and/or chemical or compositional changes.

The term “regenerated catalyst” denotes a catalyst that had become spent, as defined above, and was then subjected to a process that increased its activity, as defined above, to a level greater than it had as a spent catalyst. This may involve, for example, reversing transformations or removing contaminants outlined above as possible causes of reduced activity. The regenerated catalyst may have an activity greater than or equal to the fresh catalyst, but typically, regenerated catalyst has an activity that is between the spent and fresh catalyst.

The term “HERB” is an acronym that stands for a Hybrid, Elutriating, Riser-Bed. Any reactor that has two solids with dissimilar densities or particle sizes, operated in such a way that one of the solids is substantially elutriated from the reactor (i.e., the majority of particles are entrained in a fluid and carried out in a riser mode), whereas the other solid is substantially fluidized, but not elutriated in the reactor, as in a non-limiting example of a bubbling-bed reactor. FIGS. 9-13 are non-limiting examples of HERB pyrolysis reactors.

The term “pyrolysis” refers to the thermochemical decomposition of organic substances at elevated temperatures in the absence of oxygen. In general, pyrolysis of organic substances produces a gas (and liquid products when the gas product temperatures are reduced), and leaves behind a solid residue richer in carbon content, a char. Pyrolysis differs from other high-temperature processes like combustion and hydrolysis in that it usually does not involve reactions with oxygen, water, or any other reagents. As used herein, pyrolysis shall be further stipulated to exclude the on-purpose addition of high-pressure (in excess of 4 bar) steam (typically referred to as “reforming”), and the on-purpose addition of high-pressure (in excess of 4 bar) hydrogen (typically referred to as “hydrotreating”), although these techniques may be used post-pyrolysis on the pyrolysis products for further upgrading. In addition, pyrolysis, as used herein, shall not exclude water or hydrogen added with reagents at lower pressure or as a part of a mixture with reagents, including but not limited to, water added into the gaseous fluidization media, or moisture carried into the pyrolysis reaction sorbed on the solid carbonaceous material or catalyst.

The so-called proximate analysis of coal is an assay of the moisture, ash, volatile matter, and fixed carbon as determined by a series of prescribed or standard test methods. It serves as a simple means of determining the distribution of products obtained when a coal sample is heated under specific conditions. By definition, the proximate analysis of coal separates the products into four groups, which are (1) moisture; (2) volatile matter, consisting of gases and vapors driven off during pyrolysis; (3) fixed carbon, the nonvolatile fraction of coal; and (4) ash, the inorganic residue remaining after combustion. The standard test method for proximate analysis (ASTM D-3172) covers the methods of analysis associated with the proximate analysis of coal and coke and is, in fact, a combination of the determination of each of three of the properties and calculation of a fourth. Moisture, volatile matter, and ash are all determined by subjecting the coal to prescribed temperature levels for prescribed time intervals. The losses of weight are, by stipulation, due to loss of moisture (at about 107° C. for 1 hour) and loss of volatile matter (at about 950° C. for 7 minutes). The residue remaining after ignition at the final temperature is called ash. Fixed carbon is the difference of these three values summed and subtracted from 100. In low-volatile materials, such as coke and anthracite coal, the fixed-carbon value equates approximately to the elemental carbon content of the sample. Although these procedures were initially developed for coal, the same ASTM methods have been widely used for biomass and other organic substances. In this application, any references to volatile matter, fixed carbon, ash, and moisture on any solid carbonaceous material, both received or synthesized, will be understood to be measured by this method.

Because the test method for volatile matter, as described above, is designed in such a way to drive off substantially all the volatile matter contained in the starting material, this process could be described as a full pyrolysis; whereas partial pyrolysis may be characterized by partial liberation of volatile matter and achieved by adjusting pyrolysis conditions to milder conditions (e.g., lower pyrolysis temperature <950° C. and/or lower pyrolysis time <7 minutes).

Volatile matter values of coal are important in choosing the best match between a specific type of coal-burning equipment and the coal to use with the equipment. Such values are valuable to fuel engineers in setting up and maintaining proper burning rates. As a general observation, low volatile anthracite coal will not burn as fast as a high volatile bituminous coal and, therefore, these two fuel types are not necessarily interchangeable on a given boiler configuration. Thus, the amount of retained volatile matter in a pyrolyzed coal is an important quality factor, among others, determining it's suitability as a boiler fuel. For example, if the product coal is over-pyrolyzed into a semi-coke or coke like product, then this may limit its off-take option as a boiler fuel although it may be used for metallurgical applications, such as steelmaking.

The solid carbonaceous material may be pre-treated before entering the catalytic pyrolyzer. Pretreatment steps may be performed in such a way as to improve the reactivity of the starting carbonaceous material in the catalytic pyrolyzer and/or to improve the overall the quality of the products being produced in the catalytic pyrolyzer. One such pretreatment example may include comminution (e.g., pulverizing) and classification of the starting carbonaceous material in order to enhance the starting carbonaceous material's heat and mass transfer characteristics. Other examples may include removal of moisture (e.g., drying) and/or removal of ash and mineral components (e.g., washing) from the starting carbonaceous material in order to promote high reactivity of the pretreated carbonaceous material in the catalytic pyrolyzer (e.g., enhanced release and reactivity of volatile matter in the catalytic pyrolyzer).

The term “immobilized” (e.g., “immobilization,” etc.) when referring to catalyst in a reactor, means that the catalyst is prevented from exiting the reactor, not necessarily that the catalyst remains stationary or fixed in place within the reactor. Immobilization of the catalyst can be accomplished by a number of methods including, but not limited to, the following: First, the catalyst may be fixed in place via deposition, plating, or adhesion to a packing, monolith, or wall of the reactor. Second, the use of extrudates or large catalyst particles or grains of catalyst may be employed, such that the catalyst cannot be fluidized or entrained by the gas flow. Third, a size or mass exclusion where the catalyst may be fluidized, but is not carried or entrained out by the fluidization gas but the carbonaceous reactant is carried by the fluidization gas (i.e., “elutriation”) may be employed. Fourth, a size exclusion where the catalyst is prevented from exiting the reactor by sieve size allowing smaller sized carbonaceous reactant to pass the sieve but not the catalyst may be employed. For the third and fourth methods, the catalyst is not fixed in place and can move around within the reactor, but is confined to the reactor.

The term “predominantly” when referring to upgraded solid product or catalyst, such as in a stream of predominantly upgraded solid product/catalyst, means more than 50%. Thus, a stream of predominantly upgraded coal product includes more than 50% upgraded coal product.

The abbreviation HC is used to refer to hydrocarbons to generically define any molecule containing hydrogen and carbon atoms. We also will often denote hydrocarbons by the number of carbon atoms contained in the molecule by the formal C_(x) where x is the number of carbon atoms contained in the hydrocarbon. For example, C₁, C₂, and C₃ will be understood to mean any hydrocarbon containing 1, 2, or 3 carbons, respectively.

The term “separating” when referring to the separation of solids, liquids, gases, or any combination thereof does not necessarily mean 100% separation occurs. Even when pure separation may be desirable, it should be understood that 100% separation is generally not obtainable, so the term “separation” means as close to 100% separation as is practicable.

Referring generally to the Figures, disclosed are systems and processes for an integrated thermal pyrolysis and catalytic conversion of coal to obtain a beneficiated coal product stream which is substantially reduced in moisture, sulfur, mercury, nitrogen, and oxygen content; and to obtain a hydrocarbon-rich product stream which is substantially free of high molecular weight tars and hetero-atom containing compounds. The process combines a set of unit operations including a catalytic pyrolysis reactor, a catalyst regeneration unit, and at least partial product separation into gaseous, liquid, and solid product streams. A solid-solid separation step is included in the process to separate upgraded (e.g., beneficiated) coal product from the spent catalyst. The process may also include a gaseous separator, such as, for example, an acid gas removal (AGR) system, which removes or separates undesirable compounds and/or elements from the gaseous product stream. An AGR system may be utilized to remove or separate any one or combination of, for example, carbon dioxide (CO₂), which has no heating value, hydrogen sulfide (H₂S), ammonia (NH₃), hydrogen cyanide (HCN), as well as any other polluting and/or sulfur carrying compounds. Products separated by the gaseous separate (e.g., the AGR) may include a sulfur containing compound stream and/or a high concentration CO₂ stream, which can be used for enhanced oil recovery, CO₂ sequestration, or other suitable purposes.

The systems and processes, as disclosed herein, may convert carbonaceous materials, such as low-grade coals, biomass, bitumen, solid waste, or any suitable carbon-carrying material into a set of usable products including an upgraded carbonaceous product, as well as gas and liquid products. A carbonaceous raw material releases volatile matter when heated to pyrolysis temperatures. Less suitable carbonaceous materials would include those such as coke, which has been substantially depleted of its volatile matter content. The catalytic pyrolysis reactor converts some or all of the volatile matter into a gaseous product and some portion of the volatile matter may also be converted into a solid char or coke residue. The remaining solid material is an upgraded solid stream with higher heating value (higher energy density) and lower polluting elements, such as sulfur, mercury, and/or nitrogen, compared to the starting carbonaceous material. Some light hydrocarbon compounds (e.g., C₁ to C₃) may be co-fed to the pyrolyzer and/or recovered from the hydrocarbon product stream and recycled back to the pyrolyzer.

The systems and processes, as disclosed herein, may utilize any combination of, for example, a pyrolysis reactor (e.g., system, unit, etc.), a catalyst regeneration reactor (e.g., system, unit, etc.), and/or a solid-solid separation system (e.g., unit). A catalyst may be utilized in the systems and processes to convert the solid carbonaceous materials into a usable gaseous product, a usable liquid product, a usable solid product, or any combination thereof.

The pyrolysis reactors, as disclosed herein, may utilize a process that is a relatively mild in temperature and has a short duration in time, thereby promoting partial catalytic pyrolysis, as opposed to a full removal of volatile matter, of the solid carbonaceous material. The mild temperature pyrolysis reactors may operate from about 300° C. about 1100° C. In some embodiments, the pyrolysis reactors may operate from about 350° C. to about 850° C. In other embodiments, the pyrolysis reactors may operate from about 400° C. to about 700° C. The pyrolysis reactors utilizing mild temperature conditions and partial pyrolysis processes provide many advantages compared to other technologies, several of which are discussed herein. First, the milder operating conditions (e.g., temperature) are less energy intensive. Second, the gas product stream recovered contains less tars. For example, an amount of light oils (e.g., non-tars, which may include LPGs) produced is greater than an amount of tars produced by the processes of this application. According to some embodiments, a ratio of the weight of light oils produced in the processes (of this application) to the weight of tars produced in the processes is greater than 0.3. According to other embodiments, the ratio is greater than 1. The pyrolysis reactors, as disclosed herein, may yield a relatively high product weight ratio of light oil products to tar products, much greater than 1 (e.g., 5-1000, or greater). This simplifies the product handling and/or eliminates tar production, which is encountered in other coal pyrolysis processes. Third, the systems may produce three different phases of usable products, each of which can be used for a wide variety of purposes including, but not limited to, a fuel or a chemical precursor. For example, the systems may produce a usable solid product (e.g., a solid stream), a usable liquid product (e.g., a liquid stream), a usable gaseous product (e.g., a gaseous stream), or any combination thereof. The solid stream contains a significantly upgraded quality of solid carbonaceous matter, which can be used as fuel or processed further, such as for full gasification. The physical states of matter for the fluid streams may be liquid or gaseous depending on the temperature and pressure of the particular stream. The fluid streams may contain a fraction of high value olefins and aromatics that can be separated or sold in bulk as synthetic crude oil to be processed in existing refineries. The fluid streams may also contain a variety of chemicals that can be used as fuels within the plant or separated for saleable fuels (e.g., hydrogen, carbon monoxide, LPGs, natural gas liquids (NGL), etc.), as monomers, and/or as intermediates for subsequent chemical processes. Fourth, by running the pyrolysis reactors at mild temperature conditions only a portion of volatile matter will be liberated from the starting solid carbonaceous material, the remainder of which will be retained in the upgraded solid product, such as upgraded solid coal product so that the upgraded solid coal product is more suitable for downstream combustion operations.

FIG. 1 illustrates an illustrative embodiment of a system 100 configured to use a solid carbonaceous material, such as, for example low-grade coal. As shown, the system includes a pulverizer 101, a dryer 102, an assembly for performing the pyrolysis (e.g., a pyrolysis reactor 103, a pyrolyzer, etc.), a separator (e.g., a condenser 104, a classifier 105, a product separation unit 106, etc.), and a regenerator 107 (e.g., regeneration assembly, regenerator unit, regeneration reactor). The coal is introduced into the pulverizer 101 via a pipe 111 (e.g., conveyor, tube, etc.) for pre-processing to reduce the size of the coal into appropriate sized particles, which are then passed into the dryer 102, such as through a pipe 112. The pulverizer 101 may include an inlet 113 configured to introduce air (e.g., relative dry air) into the pulverizer to help dry the coal during pulverization and an outlet 114 configured to remove relatively wet air from the pulverizer 101. In the dryer 102, the coal particles are subjected to a drying gas (e.g., air) to reduce the moisture content in the coal particles. The dryer 102 includes an inlet 121 for introducing relatively dry air and an outlet 122 configured to exit the relatively wet air from the dryer 102. The dried coal is then passed from the dryer 102 to the pyrolysis reactor 103, such as through an inlet pipe 123 (e.g., a first inlet) that fluidly connects an outlet of the dryer 102 to an inlet of the pyrolysis reactor 103.

In the pyrolysis reactor 103, the coal and the catalyst come into contact. The catalyst may be introduced via a second inlet. According to one non-limiting example, the reactor 103 includes a second inlet 132 configured to introduce fresh catalyst (e.g., previously non-reacted catalyst) and a third inlet 133 configured to introduce regenerated catalyst into the reactor 103. The catalyst may be an acid catalyst, a fluid cracking catalyst, a hydrocracking catalyst, and the like. One or more catalyst types may be used at the same time. Such catalysts and supports for such catalysts may include, but are not limited to metals such as Mo, Zn, Ga, Pt, W, Ni, V, Co, Mn, or Cu; metal oxides; carbon-based materials; and mixtures of any two or more thereof. Illustrative examples of such catalysts and catalyst supports may include, but are not limited to, platinum, palladium, ruthenium, osmium, nickel, cobalt, rhenium, molybdenum, zinc, gallium, tungsten, vanadium, manganese, copper, or a mixture or alloy of any two or more such metals, natural zeolites, synthetic zeolites, carbon nanotubes, graphene, graphite, alumina, and silica. The catalysts may be microporous (pore size up to 2 nanometers) in some embodiments. In other embodiments, the catalyst may be mesoporous (pore size from 2 to 50 nanometer) or macroporous (pore size greater than 50 nanometers). And in other embodiments the catalyst material may be a hybrid containing any combination of micrporous, mesoporous and macroporous structures.

Some zeolites, although not necessarily all, may be of the formula Mx/n[(AlO₂)x(SiO₂)y].mH₂O, where M is an alkaline or alkaline earth metal, x and y are the total number of tetrahedra per unit cell where the ratio of y/x is from about 1 to about 5 for an alumina-based zeolite, or y/x is from about 10 to about 100 for a silica zeolite. With M as an alkaline or alkaline earth metal, n is 1 or 2. The ratio of Si/Al in the formula may range from 12:1 to 1000:1. In some embodiments, the ratio of Si/Al in the formula is from 14:1 to 500:1. In some embodiments, the ratio of Si/Al in the formula is from 15:1 to 250:1. In the general formula m is the number of water molecules of crystallization. Other synthetic zeolites are generally known and may be used as well. Illustrative zeolites include, but are not limited to, those with topologies AEL, BEA, CHA, EUO, FAO, FAU, FER, KFI, LTA, LTL, MAZ, MOR, MEL, MTW, LEV, OFF, TON, MWW, MCM and MFI. Zeolites may also include those such as, but not limited to, ZSM-5, PSH-3, ITQ-2, ZSM-12, MCM-22, MCM-36, MCM-49, MCM-56, MCM-58, MCM-68, H-Beta, H—Y, H—USY, H-MOR and HZ SM-5. Illustrative unit cell compositions of zeolites include, but are not limited to, Na₁₂[(AlO₂)₁₂(SiO₂)₁₂].27H₂O; Na₆[(AlO₂)₆(SiO₂)₁₀].12H₂O; (Na,TPA)₃[(AlO₂)₃(SiO₂)₉₃].16H₂O; Na₈₆[(AlO₂)₈₆(SiO₂)₁₀₆].264H₂O; Na₅₆[(AlO₂)₅₆(SiO₂)₁₃₆].250H₂O; and Na₈[(AlO₂)₈(SiO₂)₄₀].24H₂O, where TPA is tetrapropylammonium. Other frameworks as described by the Famework Type Code (FTC) may also be used.

Some zeolites, although not necessarily all, may be of the formula |M_(x/n)(H₂O)_(y)|[Al_(x)Si_((t-x))O_(2t)]-IZA, where the guest species are listed between the braces (“| . . . |”) and the host framework is listed between the brackets (“[ . . . ]”). M represents a charge-balancing cation, x is the number of framework Al atoms in the unit cell, n is the cation charge, y is the number of adsorbed water molecules, t is the total number of framework tetrahedral atoms in the unit cell (Al+Si), and IZA is the code for the framework type assigned by the Structure Commission of the International Zeolite Association.

The zeolites for use in the systems and processes, as disclosed herein, can be post-treated (e.g., by de-alumination or by ion exchange, such as is required to convert, for example, the sodium form to H-form (e.g., H-Beta, H—Y, H—USY, H-MOR and HZSM-5). Such de-aluminated zeolites may, for example, help promote ethylene oligomerization. Also, for example, the zeolite particles may be densified (e.g., post-processed to increase the bulk density of the particles).

The catalysts may have a wide range of pore sizes (e.g., average pore size). For example, the catalyst may have a pore size from about 0.26 to about 0.74 nm. This includes catalysts with a pore size from about 0.26 to about 0.57 nm, about 0.28 to about 0.48 nm, about 0.31 to about 0.45 nm, as well as from about 0.51 to about 0.55 nm, about 0.53 to about 0.56 nm, and about 0.65 to about 0.70 nm. For example, an A zeolite (e.g., having an LTA structure) may have a pore size of about 0.41 nm. Also, for example, a P zeolite (e.g., having a GIS structure) may have a pore size of about 0.31×0.45 nm. Also, for example, a ZSM-5 zeolite (e.g., having an MFI structure) may have a pore size of about 0.53×0.56 nm. Also, for example, a ZSM-5 zeolite (e.g., having an MFI structure) may have a pore size of about 0.53×0.56 nm or about 0.51×0.55 nm. Also, for example, an X zeolite (e.g., having an FAU structure) may have a pore size of about 0.74 nm. Also, for example, a Y zeolite (e.g., having an FAU structure) may have a pore size of about 0.74 nm. Also, for example, a Mordenite zeolite (e.g., having an MOR structure) may have a pore size of about 0.65×0.70 nm or about 0.26×0.57 nm. The pore sizes provided in this application are examples, and are not limiting in nature.

The pyrolysis reactors may operate from about 300° C. to about 1100° C. The carbonaceous material may have a residence time of 0.01 seconds to about 5 hours. In some embodiments, the residence time is from about 0.1 second to about 1 minute. The catalyst loading for the pyrolysis reactor may be from about 0.01 g catalyst/g carbonaceous feed material to about 100 g catalyst/g carbonaceous feed material. In some embodiments, the catalyst loading is from about 0.05 g catalyst/g fee to about 20 g catalyst/g feed. In yet other embodiments, the catalyst loading is from about 0.1 g catalyst/g feed to about 10 g catalyst/g feed. The heating rate of the carbonaceous material being introduced into the pyrolysis reactor may be from about 0.1° C./second to about 1000° C./second. However, it is noted that flash pyrolysis can involve a heating rate in the reactor in excess of 1000° C./second.

Also shown in FIG. 1, the solids are passed from an outlet of the pyrolysis reactor 103 to the classifier 105 via a pipe 134. The pyrolysis reactor 103 may include other outlets. For example, gas products may be removed from the pyrolysis reactor 103 by way of a second outlet and passed through a line 135 (e.g., pipe) to, for example, the condenser 104 for further processing (e.g., separation). The classifier 105 is configured to separate the upgraded coal product, which is recovered via a first outlet 151 of the classifier, and the spent catalyst, which is recovered via a second outlet 171 of the classifier.

According to one illustrative embodiment, the pyrolysis reactor is a fluidized bed where the coal and catalyst are suspended in a gaseous phase and mixed for a desired reaction residence time. The solids may be separated in the reactor to produce a first solid stream containing predominantly upgraded coal and a second solid stream containing predominantly spent catalyst. Upgraded coal generally refers to low ranked coal (e.g., sub-bituminous, lignite, etc.) that has been altered (e.g., improved), such as by removing moisture and/or pollutants, to increase the efficiency and/or reduce the emissions of the coal when burned (e.g., combusted). As an example, catalytic pyrolysis of the coal may take place at a temperature of about 350° C. to about 850° C., and may have a residence time from 0.1 second to about 1 minute during the catalytic process.

The first solid stream of upgraded coal can be removed from the reactor for further processing or use. For example, the upgraded coal can be pelletized or briquetted for purposes of transporting the upgraded coal elsewhere. Also, for example, the upgraded coal can be used within the plant as a solid fuel. The stream of solid product may have a certain amount of spent catalyst carried over with it. The second solid stream (e.g., a used catalyst stream), which may contain some upgraded coal, is transferred (e.g., transported), such as through a pipe or conveyor, to the regenerator where it is mixed with air or any suitable oxygen-carrying gas to burn off any coke and/or residual coal on the spent catalyst to regenerate the catalyst.

As shown in FIG. 1, the spent catalyst is separated by the classifier 105 and sent to the regenerator 107 via a line 171 (e.g., pipe) for regeneration (e.g., rejuvenation, etc.) in the form of a spent catalyst stream. The spent catalyst stream may come directly from the pyrolysis reactor, such as for pyrolysis reactors that perform solid-solid separation internally. An oxygen-containing gas stream may be introduced into the regenerator 107, which may be used to combust all or nearly all of the combustible matter, such as coke, coal, etc., that is carried within the spent catalyst stream into the regenerator 107. The regenerator 107 includes an inlet through which the gas stream enters the regenerator. The gas inlet may be the same as or different than the spent catalyst stream inlet. For example, gas (e.g., air) may be introduced through a gas inlet 172. The regenerator also includes an outlet line 174 (e.g., pipe) through which the regenerated catalyst stream exits, such as to enter the pyrolysis reactor. In the regenerator, air or another suitable oxygen-carrying gas is introduced to burn at least a portion of the coke/coal off of the spent catalyst to regenerate the spent catalyst. The regenerator 107 may include an outlet 173 through which regenerator exit gas, such as flue gas, exits the regenerator. Optionally, at least a portion of the regenerator exit gas may be used to carry the regenerated catalyst to the pyrolysis reactor. A small purge of the regenerated catalyst may be used to prevent the accumulation of the ash or other impurities. For example, a purge valve 175 may be provided in-line between the outlet line 174 and a pipe connecting a first outlet of the purge valve 175 to the third inlet 133 of the pyrolysis reactor 103. A second outlet 176 of the purge valve 175 is configured to pass the purged catalyst from the system.

Once regenerated, the catalyst may be returned to the pyrolysis reactor 103 for further catalytic pyrolysis of coal. For example, the regenerated catalyst may be reintroduced into the pyrolysis reactor 103 via the third inlet 133. The pyrolysis reactor 103 may include additional or fewer inlets and/or outlets. For example, the reactor may include first and second outlets, where the solid stream is configured to exit the reactor through the first outlet and the fluid stream is configured to exit the reactor through the second outlet.

A portion of the gas exiting the regenerator may include a portion of catalyst (e.g., fines), which may be recovered and recombined with a portion of regenerated catalyst in the regenerated catalyst stream or introduced directly into the pyrolysis reactor to maintain a desired catalyst-to-coal ratio. The catalyst-to-coal ratio may be, for example, from about 0.001 g catalyst/g carbonaceous feed to about 100 g catalyst/g carbonaceous feed. In some embodiments, the catalyst-to-coal ratio is from about 0.01 g catalyst/g carbonaceous feed to about 100 g catalyst/g carbonaceous feed. In other embodiments, the catalyst-to-coal ratio is from about 0.05 g catalyst/g carbonaceous feed to about 20 g catalyst/g carbonaceous feed. In yet other embodiments, the catalyst-to-coal ratio is from about 0.1 g catalyst/g carbonaceous feed to about 10 g catalyst/g carbonaceous feed. Other reactive or nonreactive solids may be included in the catalyst regeneration cycle as a heat source. For example, sand can be recirculated with the catalyst, where the sand absorbs excess heat in the regenerator. The hot sand is carried into the pyrolysis reactor where its heat is absorbed by the incoming carbonaceous solid material.

The fluid product stream out of the pyrolysis reactor may be transferred downstream for further processing. For example, the fluid product stream may be transferred to a set of unit operations where the fluid product stream is separated into one or more liquid hydrocarbon product streams, one or more gaseous product streams, one or more aqueous streams, and/or a combination of any two or more such streams. As shown in FIG. 1, the fluid product stream is passed from the pyrolysis reactor 103 to a system (e.g., a condenser 104) configured to act as a partial condenser affecting a gas-liquid separation. The condenser 104 may also serve the function of a liquid-liquid decanter allowing for separation of an aqueous liquid phase from a hydrocarbon liquid phase due to immiscibility. As shown, a gas stream is passed, such as through a line 141 (e.g., an outlet pipe), from an outlet of the condenser 104 to a product separation unit 106 for further processing. According to an exemplary embodiment, organic liquids are separated from aqueous liquids by the condenser 104, where the organic liquids are removed from the condenser 104 via a second outlet line 142 (e.g., pipe) and the aqueous liquids are removed from the condenser 104 via a third outlet line 143 (e.g., pipe). Part, or all, of each aqueous and/or hydrocarbon liquid stream may be used downstream in, for example, other systems or processes in the plant (e.g., facility). In one such example, at least a portion of an aqueous liquid stream and/or a portion of a hydrocarbon stream may be used for briquetting the coal product stream. The liquid hydrocarbon stream may be packaged as synthetic crude oil, or further separated into specific product streams, such as, for example, a BTEX and/or a BTX (e.g., mixtures of aromatic hydrocarbons such as, but not limited to, benzene, toluene, and the three xylene isomers) rich stream. The liquid hydrocarbon stream may also be processed further by chemical upgrading in other chemical reactors, such as for the purpose of de-oxygenation of any oxygen carrying products. The gaseous product stream may be used in the plant as a fuel or separated into one or more than one useable product stream.

As part of the separation units of the gas and liquid products, the product stream may be processed through an acid gas removal system to capture sulfur-carrying compounds, nitrogen-containing compounds (e.g., ammonia or hydrogen cyanide), and/or carbon dioxide. The carbon dioxide-rich stream can be sequestered, sold and transported, or used for enhanced oil recovery. As shown in FIG. 1, the CO₂ stream can be separated by the product separation unit 106 and removed via a first outlet line 161 (e.g., pipe). The sulfur-carrying compounds may be processed further before being packaged as a sulfur-carrying product (e.g., as elemental solid sulfur, as sulfuric acid, etc.), or sent to a landfill. Also shown in FIG. 1, the sulfur-carrying compounds can be separated by the product separation unit 106 and removed via a second outlet line 162 (e.g., pipe). The acid gas removal system may be one of the first separation processes of the fluid product stream exiting the pyrolysis reactor, or may be further downstream in the separation process. Other compounds/products may be recovered as well. For example, the product separation unit 106 may be configured to separate hydrocarbons, such as from the gas stream, and pass the recovered hydrocarbons via a third outlet line 163 (e.g., pipe).

Heat from other processes in the system may be used as input heat into the pyrolysis reactor, such as to heat the carbonaceous material. For example, heat from the hot regenerated catalyst may be used to provide heat and to maintain a desired temperature in the pyrolysis reactor. Also, for example, the flue gas exiting the catalyst regenerator may be used to provide heat either directly, or indirectly, to the dryer and/or pyrolysis reactor. The flue gas exiting the regeneration unit may be mixed with some of the gas product stream and combusted to generate heat for the dryer, the pyrolysis reactor, and/or other devices, processes, or units in the plant. The mixing of the flue gas with some of the combustible gas may advantageously further reduce the oxygen content in the flue gas. The non-condensable gas stream may be combusted with plant air, fresh air, and/or air from within the process to provide heat to the dryer, pyrolysis reactor, regeneration reactor, and/or other devices, processes, or units within the plant. This combusted gas may also be used to generate steam, such as for use within the facility.

According to one embodiment, the regeneration reactor uses a pure oxygen stream or an oxygen rich stream to combust all or most combustible matter on the spent catalyst or the carbonaceous matter that is carried over into the regeneration reactor. According to another embodiment, an oxygen lean (e.g., where the oxygen content is diluted to less than 2%) stream is utilized with the regenerator. According to other embodiments, hydrogen, steam, CO₂, CO, or any combination thereof is used to remove the carbon off the spent catalyst. In yet another embodiment, oxygen is mixed with the previously mentioned chemicals to remove the coke on the spent catalyst. In all these embodiments, the exiting gas stream may be rich in CO₂ which can be separated for sequestration, enhanced oil recovery, or other suitable purposes. According to one example, at least a portion of any unpyrolyzed coal, coke, and carbonaceous material is removed from the catalyst by at least one of combustion, steam, and a reducing gas.

According to one embodiment, the solids of the pyrolysis reactor are removed from the reactor and separated ex situ into a predominantly solid stream and a predominantly spent catalyst stream (e.g., a stream that has more than 50% catalyst). Since the cost of the catalyst is significantly higher than the carbonaceous material, it is desirable to keep and recycle as much catalyst as possible. Thus, the solid-solid separation may be tailored to minimize the amount of catalyst that is comingled with the solid stream, even at the expense of increasing the amount of carbonaceous material that is comingled with the spent catalyst stream. According to an exemplary embodiment, eighty percent (80%) by weight or more of the spent catalyst is captured during the solid-solid separation. Preferably, ninety percent (90%) by weight or more of the spent catalyst is captured during the solid-solid separation.

This solid-solid separation can be performed by any number of separation processes including, but not limited to, classifiers, magnetic separation, electro-static separation, or a combination of any two or more such separation processes. For example, the particle size distributions of carbonaceous material and the catalyst are intentionally different, allowing for appropriate classification technology to separate the two solids by differences in particle size, weight and/or density. In one such example, the carbonaceous material enters the pyrolysis reactor with average size particles from about 100 μm to about 300 μm. In another such example, the carbonaceous material has average size particles from about 10 μm to about 100 μm. In one example, the catalyst enters the pyrolysis reactor with average size particles of about 300 μm to about 500 μm. In another such example, the catalyst has average size particles from about 500 μm to about 1000 μm. A classifier is used to effectively separate the upgraded solid product from the catalyst. In another embodiment, the solid stream exiting the regenerator may also be separated to remove all or some of the ash and/or impurities before the regenerated catalyst stream is returned to the pyrolysis reactor. For example, the solid stream may be demineralized and/or demetalized to remove impurities. A wet process, solid-liquid process, or any other suitable process may be used to rejuvenate the spent catalyst. “Fresh” catalyst as make-up catalyst could be supplied by a vendor, whom has rejuvenated and/or demetalized spent catalyst from other sources, such as, for example, reusing catalyst from a pyrolysis process discussed in this application or reusing a catalyst from a conventional fluidized catalytic cracking (FCC) process. Stated differently, the “fresh” catalyst does not have to consist of only “virgin” (e.g., unreacted) catalyst, but may be a mixture of “virgin” catalyst and rejuvenated catalyst.

Some, or all, of the air streams may be used within the system (e.g., the process of the system) or elsewhere in the facility. For example, the air exiting the pulverizer may be used as over-fire air in the boiler to reduce NO_(x) (e.g., nitrous oxides, nitric oxides, etc.) production in the furnace. Similarly, the flue gas from the regenerator and light gas products from the pyrolysis reactor (CO, H₂, methane, ethane and ethylene) may be used in the furnace and mixed with other chemicals for its heating value and as a reburn stream or chemical injection for de-NO_(x) purposes.

In any of the above embodiments, the pyrolysis reactor may be configured such that both catalyst and carbonaceous solid materials enter and exit the pyrolysis reactor at controlled rate(s) (e.g., flow rate, movement rate, etc.). In another embodiment, the pyrolysis reactor may be configured such that the catalyst is immobilized within the pyrolysis reactor while the solid carbonaceous material enters and exits the reactor. In either embodiment, a carrier gas may, or may not, be utilized to pneumatically transport the movable solids through the reactor and to hydrodynamically enhance mixing and chemical conversion in the reactor. With an immobilized catalyst in the reactor, the need for ex-situ solid-solid separation may be eliminated.

FIGS. 2 and 3 illustrate other illustrative embodiments of systems configured to produce a usable solid stream, a usable liquid stream, and/or a usable gaseous stream from a feedstock (e.g., a carbonaceous feedstock, such as coal). The systems shown in FIGS. 2 and 3 are similar to the system of FIG. 1, except each system is configured to introduce a recycled gas (that is taken from another process in the system) into the pyrolyzer. Thus, common reference numerals have been used in FIGS. 1-3 to identify common elements (e.g., components, assemblies etc.).

The system of FIG. 2 utilizes a recycled gas that has been separated from other gases via a gas-gas separator (e.g., the product separation unit 106, an AGR). The gas stream that is separated from the usable liquid(s) in a gas-liquid separator (e.g., a condenser) is then separated into two or more usable gas streams, and at least a portion of one or more of the usable gas streams is then routed back to the pyrolyzer as recycled gas. As shown in FIG. 2, the gas stream from the gas-liquid separator is separated by the product separation unit 106 into three usable gas streams, where the first is a CO₂ stream 161, the second is a sulfur-containing gas stream 162 (e.g., H₂S), and the third is a hydrocarbon gas stream 163. At least a portion of the hydrocarbon gas stream 163 is routed, such as through a line 265 (e.g., pipe), to the pyrolyzer 203 to be used therein. For example, the gas-gas separator may isolate methane, a portion of which is directed to the pyrolyzer 203 and the remainder is recovered for use elsewhere. The system 200 may optionally include a valve or other suitable device that separates, for example, a usable gas stream (e.g., the hydrocarbon gas stream) into two separate streams, such that a portion is used as recycled gas and the other is used elsewhere. The system 200 may optionally include a valve to purge a portion of the recycled gas stream between the product separation unit and the pyrolyzer. As shown in FIG. 2, a first valve 264 is configured to control a flow of the hydrocarbon gas stream 163 through the line 265 toward the pyrolyzer 203 and a flow of the hydrocarbon gas to be recovered for other purposes, and a second valve 266 is provided downstream of the line 265 to control the flow of the gas stream to be purged via a purge outlet 268 and the gas stream that is recycled back to the pyrolyzer 203 via the recycle line 267 (e.g., pipe).

Also referring to FIG. 2, and according to one example, the gas stream exiting the pyrolysis reactor 203 through a gas outlet contains a non-condensable fuel gas. The gas stream may enter, for example, an AGR system where all sulfur compounds and at least the bulk of the carbon dioxide gas are removed. The sulfur compounds can be disposed of (e.g. landfilled) or converted to a usable product, such as solid elemental sulfur or sulfuric acid. The CO₂ stream can be further purified or transferred elsewhere for other purposes, such as enhanced oil recovery. The cleaned gas stream may then be further processed to recover the light molecular weight gases (mainly methane, ethane, ethylene, hydrogen, CO) and used to fluidize the pyrolysis reactor. One advantage of recycling the light molecular weight gases back to in the pyrolyzer is that these gases have a second interaction in the pyrolyzer, prompting an increased yield of the liquid hydrocarbon fraction. Another advantage of recycling these gases back to the pyrolyzer is that it obviates the need for introducing another feed to the process (e.g., nitrogen for fluidization and as carrier gas) which lowers operating and equipment costs. The non-condensable gas fraction not recirculated in the pyrolysis reactor can also be used in the regeneration reactor, dryer, pyrolysis reactor, or burned in the boiler for added heat and/or de-NO_(x) technology. The non-condensable gas may also be fractionated by cryogenic distillation or other suitable means into individual components (e.g., methane, ethane, ethylene, hydrogen, carbon monoxide) and further processed, recycled or sold.

The system of FIG. 3 utilizes a recycled gas that has not been separated via a gas-gas separator (e.g., a product separation unit, an AGR). In other words, at least a portion of the gas stream that is separated from the usable liquid(s) in a gas-liquid separator (e.g., a condenser) is sent directly (prior to gas-gas separation) to the pyrolyzer 303 as recycled gas. The remainder of the gas stream may be sent downstream to fractionation units, such as cryogenic distillation or other suitable separation devices, to further separate the gas stream into more than one usable gas product streams. As shown in FIG. 3, the gas stream exiting the condenser 104 is piped via a line 341 (e.g., pipe) to a valve 364, which controls the flow of the gas stream to the product separation unit 106 via a line 366 (e.g., pipe) and the flow of the gas stream to the pyrolyzer 303 via a line 365 (e.g., pipe). Thus, the valve 364 controls how much of the gas exiting the condenser 104 is distributed as recycled gas to the pyrolyzer 303 and how much of the gas is distributed further processing downstream by the product separation unit 106.

Also referring to FIG. 3, according to an illustrative embodiment, the recirculated gas comes out of the first condenser 104 prior to entering the product separation unit 106. The main advantage of recovering the recirculation gas before the separation units is that the separation units can be sized smaller because they do not process the recirculating gas. The smaller size reduces equipment size and cost, as well as reduces the energy requirement for the separation. As with the embodiment in FIG. 2, the light molecular weight gases entering the pyrolysis reactor promote an increased pyrolysis yield of the liquid hydrocarbon fraction.

In yet other embodiments, the pyrolysis reaction is staged into more than one reactor system. FIG. 4 illustrates an example of such a staged reactor system. As shown, the system includes a first pyrolysis assembly 403 (e.g., a first pyrolyzer, first reactor, etc.), in which a carbonaceous feedstock material, such as coal, is pyrolyzed to produce a gaseous pyrolysis product stream and a solid product. The gas product stream is transferred from the first pyrolysis assembly 403 to a second pyrolysis assembly 408 via a first outlet pipe 435. The solid product is transferred from the first pyrolysis assembly 403 to a classifier 105 via a second outlet pipe 434.

As shown in FIG. 4, the pyrolysis reaction in the first pyrolysis assembly 403 is a catalytic reaction. In the catalytic first pyrolysis assembly, the catalyst may be fresh (i.e., new) catalyst, regenerated catalyst (e.g., from the regenerator), or any combination thereof. The solid product produced by the first pyrolysis assembly 403 is delivered to a downstream solid-solid separator (e.g., a classifier 105) via a line 434 (e.g., pipe) to separate the spent catalyst and the upgraded solid product (e.g., upgraded coal). The gaseous pyrolysis product stream produced by the first pyrolysis assembly 403 is delivered to the downstream second pyrolysis assembly 408 (e.g., a second pyrolyzer, second reactor, etc.) via a line 435 (e.g., pipe). Like with FIGS. 2 and 3, FIG. 4 also includes common reference numerals with numerals used in FIGS. 1-3, which are meant to identify similar or common elements (e.g., components, assemblies etc.). Hence, the description of the common reference numerals is not duplicated here.

As shown in FIG. 4, the second pyrolysis assembly 408 includes an inlet configured to receive the gaseous product stream from the first pyrolysis assembly, such as through the inlet line 435, and therein catalytically processes the gaseous product stream into a gaseous product and a liquid product. The second pyrolysis assembly 408 may include additional inlets. For example, the second pyrolysis assembly 408 may include a second inlet that is configured to receive fresh catalyst via a line 481 (e.g., pipe) and a third inlet that is configured to receive regenerated catalyst via a line 482 (e.g., pipe). The second pyrolysis assembly 408 may include one or more outlets. For example, the second pyrolysis assembly 408 may include a first outlet through which the gas product is transferred to the condenser 104 via a line 484 (e.g., pipe) and a second outlet through which the spent catalyst is transferred to a regenerator via a line 483 (e.g., pipe). Thus, the spent catalyst may be delivered to a regenerator to regenerate the spent catalyst. FIG. 4 illustrates a first catalyst regenerator 107 configured to regenerate the spent catalyst used in the first pyrolysis assembly 403 and a second catalyst regenerator 409, which is separate from the first catalyst regenerator 107, and is configured to regenerate the spent catalyst used in the second pyrolysis assembly 408. Having two separate regenerators may be advantageous for systems in which different catalysts are used in the two pyrolysis assemblies.

The second catalyst regenerator 409 receives the spent catalyst via an inlet line 483 (e.g., pipe) from the second pyrolysis assembly 408. An oxygen-containing gas stream may be introduced into the regenerator 409 by way of inlet line 492 and may be used to combust all or nearly all of the combustible matter carried within the spent catalyst from the second pyrolysis assembly 408. The regenerator 409 also includes an outlet line 494 (e.g., pipe) through which the regenerated catalyst exits the regenerator 409. At least a portion of the regenerated catalyst may be routed to the second pyrolysis assembly 408. The regenerator 409 may include a second outlet 491 through which regenerator exit gas, such as flue gas, exits the regenerator. Optionally, at least a portion of the regenerator exit gas may be used to carry the regenerated catalyst to the pyrolysis reactor. A small purge of the regenerated catalyst may be used to prevent the accumulation of the ash or other impurities. For example, a purge valve 495 may be provided in-line of the outlet line 494 to pass the purged catalyst from the system via line 496. Line 482 may be configured to introduce regenerated catalyst back to the second pyrolysis assembly 408. Line 482 may be downstream from the purge valve 495.

Although FIG. 4 illustrates two separate regenerators, the system may be configured having a single regenerator, such as where the same catalyst is being used in both pyrolyzers. The solid product may be sent to a first downstream process, the liquid product may be sent to a second downstream process, and the gaseous product may be sent to a third downstream process. For example, the systems may include product separation units, such as condensers, AGRs, or any other suitable separators to further refine the product output of the system.

In the pyrolysis reactor/step, a portion of the volatile matter of a solid carbonaceous feedstock is generated in the presence of solid catalyst. This feedstock can be coal of any rank (including lignite), biomass, or peat, as examples. In the reactor, it is desirable to maximize the contact between the catalyst and the solid feedstock in order to control yield and selectivity to the greatest extent possible. From this standpoint, a fluidized-bed or riser reactor would be desirable. The design of such a bed would be done in order to maximize the mixing and avoid spontaneous separation of the two solid substrates (catalyst and feedstock). Given that mixing in fluid bed and riser reactors is largely dictated by each solid's fluidization characteristics, which in turn is driven by the particle size and shape, it would be generally desirable to match size and shape of both the catalyst and the solid feedstock. On the other hand, it is desirable to separate the spent catalyst from the feedstock after the pyrolysis step, because the spent catalyst needs to be regenerated and re-used (e.g., due to its relative high cost compared to the feedstock), and the remaining solid from the carbonaceous feedstock needs to be removed and processed as a saleable co-product (along with the pyrolysis gas). Most standard, industrially available solid-solid separators typically rely on differences in size, density, and shape either by using size exclusion, fluidization, or classification in order to accomplish separation. Thus, there is an inherent trade-off in the combination of these two unit-operations. Either make the morphology of the two solids similar, thereby providing good reactive contact in the pyrolyzer while sacrificing efficient separation leading to product loss, catalyst loss, or expensive and/or exotic separation schemes, or having poor mixing in the reactor leading to low per-pass yields and/or poor selectivity of the desired products. Due to these tradeoffs, typically two separate unit operations are utilized to accomplish reaction and product separation.

One way of eliminating the downstream solid-solid separator (e.g., classifier) is to use a pyrolysis reactor configured to utilize an immobilized catalyst while the carbonaceous material enters and exits the reactor, such as via an inlet and an outlet. Immobilization may advantageously allow an intrinsic separation of the carbonaceous reactant from the catalyst without requiring an additional separation unit operation provided downstream from the reactor. However, one must also address the need to regenerate the catalyst because the catalyst cokes as a normal consequence of carrying out the pyrolysis reaction.

According to one illustrative method, three cycles are used. In the first cycle, the pyrolysis reactor is charged with catalyst, which may be preheated to reactor temperature. The reactor is heated to the desired pyrolysis temperature, and coal is introduced along with a fluidization gas. The fluidization gas may be any non-oxidizing gas, including, but not limited to, nitrogen, helium, neon, argon, hydrocarbon gases, recycled or fresh fuel gas, recycled or fresh liquefiable petroleum gases, carbon dioxide, or hydrogen. The fluidization provides mixing between the carbonaceous reactant and the catalyst solid. The reactor may be run in (a) a true batch mode, where a defined amount of carbonaceous reactant is introduced initially and kept in the pyrolysis reactor for a defined time, or (b) semi-batch, where the reactant is continuously fed into the pyrolysis reactor and continually removed via entrainment out of the pyrolysis reactor with fluidization and product gases. In case (a), residence time is controlled by fixing the dwell time of the charge, and then increasing the fluidization gas velocity to entrain the solid products and pneumatically convey the solid products out of the reactor, whereby it is recharged again with new carbonaceous reactant feedstock. In case (b), the gas velocity of the fluidization gas must exceed the entrainment velocity of the solid carbonaceous reactant and the residence time is controlled by adjusting the gas velocity to the desired amount (but should always be greater than the entrainment velocity of the solid carbonaceous feed). In both true batch and semi-batch mode, the catalyst will eventually coke. This will be apparent as the product selectivity will change. Production of hydrocarbon products will drop, and usually, selectivity will change as well. When this happens, fresh feedstock is stopped (or no more batches are added), and the reactor is put into the second cycle.

In the second cycle, the spent catalyst and upgraded carbonaceous product are separated. If it is being run as a true batch, the fluidization velocity is increased such that the upgraded carbonaceous product is entrained out of the reactor. If it is being run as in semi-batch mode, the flow of carbonaceous material feedstock into the reactor is stopped and fluidization velocity (i.e., superficial gas velocity) may be increased. In either case, once the upgraded carbonaceous product flow stops or an acceptable portion of the upgraded product has exited the reactor, then the reactor is ready for the third cycle.

In the third cycle, the reactor is then put into regeneration mode. The reactor fluidization gas is changed from the non-oxidizing gas, to an oxidizing gas, including, but not limited to, air, oxygen, nitrous, or other nitrogen oxides. The oxidizing gas may be further diluted by any inert gas. The coke is then burned off the spent catalyst in an exothermic reaction. This will create hot flue gas and the reactor may need to be cooled. This heat and hot flue gas may be captured and utilized elsewhere in the process, including but not limited to, drying of coal, raising steam for downstream acid-gas removal, pre-heating of reactants for the pyrolysis cycle, or direct flue gas injection into the coal-fired boiler or into a heat recovery steam generator.

Once the catalyst is regenerated, the reactor could then be returned to the first cycle, and pyrolysis would be started again. It is noted that by using multiple reactors and valve switching, this process could be configured in such a way that production could advantageously be run in a continuous or near continuous manner (in the case of batch-wise pyrolysis). For example, three reactors could be used in a cyclic-swing configuration, with one of the three reactors operating in each cycle at all times (i.e., one reactor in the first cycle of pyrolysis, one reactor in the second cycle of separation, and one reactor in the third cycle of regeneration).

FIGS. 8-12 illustrate exemplary embodiments of pyrolysis reactors that are configured to provide solid-solid separation in the pyrolysis reactors, which may eliminate the need for providing a downstream solid-solid separator. The pyrolysis reactors are designed to allow for maximum contact of dissimilar (e.g., size, density, shape) catalyst(s) and feedstock(s) to solve many of the problems noted above. For example, the pyrolysis reactors of FIGS. 8-12 are configured to take advantage of dissimilar size, density, and shape to maximize contacting; allow for independent control of reactor residence time of the solid feedstock and catalyst, which could substantially reduce the amount of catalyst recirculation by enabling the catalyst to absorb more coke and by-products rather than being forced out of the reactor before needed; and provide separation within the reactor, possibly eliminating the need for a separate unit operation to affect the solid/solid separation. The reactors may be configured to use flow-fields, sieves, plates, tilting, and/or solids transfer valves to continuously contact and separate the solids. Each reactor may include two solids with substantially different particle size diameter distributions (PSD), such that a properly-sized sieve will not pass most of the solids with the larger PSD and pass most of the solids with the smaller PSD. The two solids may have substantially different fluidization characteristics, such that a gas fluidization velocity exists where one solid rises (the more buoyant solid), and one solid falls (the less buoyant solid). A gas flow field may be configured to encourage the less buoyant solid downward, and the more buoyant solid upward. Each reactor may include one or more obstacles configured to encourage contacting the two dissimilar solids on their respective journeys through the reactor. Contacting may be further increased by feeding counter-currently (i.e., the less buoyant solid at the top, and taking it from the bottom, while the more buoyant solid is fed to the bottom reactor and removed from the top). Each reactor has the ability to adapt the flow field and path of the particles to provide independent control of residence time in the reactor of the solid feedstock and catalyst. The catalyst may be larger and less buoyant than the solid feedstock, and it may be desirable to keep the catalyst residence time substantially greater than that of the solid feedstock. However, each reactor may be adjustable to accommodate a number of possibilities including, but not limited to, providing longer residence for solid feedstock than the catalyst, or equal residence time for the solid feedstock and the catalyst, as well as providing solid feedstock that is less buoyant than that of the catalyst.

FIGS. 8-10 illustrate a pyrolysis reactor 503 configured to provide solid-solid separation of a feedstock and a catalyst. The reactor 503 includes a housing 530 having a generally elongated tubular shape that defines an internal core chamber 532 that can be divided into a plurality of sub-chambers 532 a-532 g with a varying flow field to provide mixing and disengagement in each chamber. The housing 530 has an inlet end 533 configured to introduce a feedstock, such as low grade pulverized coal, into the housing. The housing 530 has an outlet 534 at an opposite end from the inlet end 533. The upgraded feedstock, such as upgraded coal product, exits via entrainment with any gases exiting the reactor via the outlet end. Optionally, the reactor may include one or more fixed plates in the core chamber. As shown in FIG. 8, the reactor 503 includes a first fixed plate 536 that is provided between the inlet end 533 and a first plate assembly 541, and also includes a second fixed plate 537 provided between the outlet end 534 and a sixth plate assembly 546. Each fixed plate 536, 537 may be configured having a plurality of holes (e.g., apertures, openings, orifices, etc.), similar to or the same as the sieve plates discussed below.

The core chamber 532 can be divided into the sub-chambers 532 a-532 g by way of one or more movable plate assemblies. As shown in FIG. 8, the reactor includes six plate assemblies 541-546. However, other examples of reactors may be configured having a greater or fewer number of plate assemblies.

Each plate assembly 541-546 may include at least one plate. As shown in FIGS. 9 and 10, each plate assembly includes a solid plate 548 (e.g., a plate having no orifices, holes, or apertures) and a sieve plate 549 (e.g., a plate having at least one orifice, hole, or aperture, and according to an exemplary embodiment a plate having a plurality of apertures) where each plate (e.g., solid, sieve) can be moved independently relative to the housing 530 (and core chamber) to control the flow between a pair of adjacent sub-chambers of the reactor 503. For example, each plate 548, 549 may be configured to slide between a fully open position, in which the entire plate is positioned outside the core chamber 532 (e.g., outside the housing), and a fully closed position, in which the plate covers the entire cross-sectional area of the core chamber. Each plate may be positioned at a plurality of intermediate positions between the fully open and fully closed positions. When a solid plate 548 is in the fully closed position, flow through the core chamber is completely blocked by the solid plate. When a sieve plate 549 is in the fully closed position, flow around the plate is prohibited, but flow through the one or more apertures of the sieve plate can occur. At the various intermediate positions, the plates influence the flow (e.g., increase the flow, restrict the flow). The sieve plates 549 are configured to pass a feedstock (e.g., a carbonaceous material, such as low grade coal) while preventing catalyst from passing. Each plate assembly may be configured to be moved from the same side (e.g., a top side) of the housing, such that a gap between a distal end of the plate and the housing forms on the same opposing side (e.g., a bottom side) of the housing 530 when the plates are at least partially open. Alternatively, the reactors having two or more plate assemblies may be configured having plate assemblies moving from different sides of the housing, such as to provide gaps on alternating sides of the reactor.

The alignment of the reactor 503, such as relative to vertical and horizontal, may be varied to change the relative angle of the reactor. For example, the angle of the reactor may be adjusted to be any angle from 0 (zero) degrees to 90 (ninety) degrees. The reactor may be configured to form catalyst beds (e.g., an agglomeration of catalyst particles) having different sizes by adjusting the plates and the angle of the reactor. The angle of the reactor is used to create varying cross-sectional area in each of the chambers. This changes the effective fluidization velocity throughout the chamber. The velocity flow-field can be further manipulated by varying the sieve plate and/or solid plate position as well. In other words, the size of the catalyst beds may be tailored by adjusting the plates and angle of the reactor. This arrangement provides a very flexible geometry which advantageously helps manipulate the solids and fluidization medium (usually a gas, but possibly a liquid), to create maximum mixing while avoiding plugging and bridging in the solids flow. FIG. 9 shows a portion of the housing 530 and core chamber 532 having a single plate assembly including a sieve plate 549 and a solid plate 548, which are able to move relative to the housing 530 and independent of one another. As shown, both the sieve plate 549 and the solid plate 548 are in intermediate positions.

FIG. 10 shows some of the features of the geometry of a mixing chamber (e.g., the mixing within the sub-chamber 532 b). It is readily apparent that the available cross sectional area for flow varies markedly in the chamber. For the sake of understanding the flow, but not limiting the reactor to any particular theory or explanation, four aspects/features to controlling the flows and mixing are further described. First, the line A₁ denotes the cross sectional area available for the less buoyant solid to fall into the lower chamber. Second, the line A₂ denotes the cross sectional area available for the more buoyant solid and the fluidization medium to rise from the lower chamber. Third, the line A₃ denotes the widest cross sectional area available for transport in the chamber. Fourth, the arrow Q_(fluid) denotes the flow of fluidization medium in the sub-chamber. The velocity (u) of the fluidization gas or of either solid can be roughly estimated by dividing its volumetric flow by the cross sectional area available for flow. Therefore, the downward flow of the less buoyant solids at its most choked point would be given by position 1 and can be calculated using calculation (1) below.

u ₁ ^(less buoyant solid) =Q _(less buoyent solid) /A ₁  (1)

The importance of this point is that solids can become plugged due to bridging during in solids transfer and storage. However, the upward fluidization velocity can assure that the solids do not stagnate in the sub-chamber. The fluidization velocity is determined by the cross sectional area at position 2 and can be calculated using calculation (2) below.

u ₂ ^(fluid) =Q _(fluid) /A ₂ ≧u _(crit) ^(more buoyant solid) and u _(mf) ^(less buoyant solid)  (2)

Preferably, this fluidization velocity is greater than, or equal to, the critical entrainment velocity of the more buoyant solid. In some embodiments, the fluidization velocity is greater than or equal to the minimum fluidization velocity of the less buoyant solid. This will create a churning, turbulent zone as the solids are forced upward by the fluidization media, preventing solids plugging as the less buoyant particle falls out of the chamber, and mixing the two dissimilar solids through the turbulence.

Position 3 (e.g., line A₃) in FIG. 10 is the point where the maximum cross sectional area is available for flow. At point 3, the fluidization velocity is the lowest, which can be calculated using calculation (3) below. This allows a significant amount of independent tuning to allow for separation and increase contact time. If a degree of separation and good contacting is desired, this velocity can be tuned to be less than the fluidization velocity of the less buoyant solid, creating a quiescent zone of lightly bubbling less buoyant particles and forcing the more buoyant particles to pass through.

u ₃ ^(fluid) =Q _(fluid) /A ₃ ≦u _(mf) ^(less buoyant solid)  (3)

One advantage of a tilted reactor (e.g., relative to vertical) is that the tilt can be used to adjust these various velocities to maximize mixing and separation. Also, for the example of pyrolysis, pyrolysis gas is evolved during the reaction and flows together in the same direction with the fluidization gas, increasing the overall amount of gas flow along the length of the reactor, leading to increased superficial gas velocity along the length of the reactor. This can be accounted for by varying the tilt or the volume in each chamber (e.g., by adjusting the plate spacing). Varying tilt can also be accomplished by series reactors, or by bending the pipe. Additionally, the configuration of the reactor of FIG. 8-10 allows the more buoyant and less buoyant solids residence times to be controlled independently, as their paths are different through the vessel. In a co-current, entrained riser, all solids and fluidization media residence times are roughly the same and dictated by the fluidization characteristics. For the case where one of the solids is a catalyst, and the other solid carbonaceous material is a feedstock to be reactive, it is desirable to independently control these residence times. Finally, in vessels with multiple staging, extra coal separation could be accomplished by feeding the more buoyant material at a higher stage than the bottommost stage, giving it more chance to disengage from the less buoyant material. In this case, this lower stage (below the injection of solid carbonaceous feed coal) could be used to regenerate spent catalyst using an oxidizing gas.

The reactor 503 may include a second outlet 538 that is configured to pass spent catalyst, such as to a regenerator. Also shown in FIG. 8, the second outlet 538 is provided near the inlet end 533 of the housing 530. For example, the second outlet 538 may be provided in the bottom side of the first sub-chamber between the first fixed plate and the first plate assembly. The reactor 503 may include a second inlet 539 that is configured to introduce catalyst (e.g., new catalyst, regenerated catalyst, a combination thereof). Also shown in FIG. 8, the second inlet 539 may be provided near the outlet end 534 of the housing 530. For example, the second inlet 539 may be provided in a top side of the seventh sub-chamber between the second fixed plate and the sixth plate assembly. This arrangement may advantageously utilize gravity in bringing the catalyst from the second inlet toward the second outlet.

FIG. 11 illustrates another illustrative embodiment of a pyrolysis reactor 603 configured to provide solid-solid separation of a feedstock and a catalyst. The reactor 603 includes a housing 630 having a generally elongated tubular shape extending from a first end 631 to a second end 632. According to one example, the reactor 603 is aligned substantially vertically, with the first end 631 at a bottom side and the second end 632 at a top side. According to other examples, the reactor 603 can be tilted, such as to be aligned at an oblique angle relative to vertical. The reactor 603 may include one or more plate assemblies that are configured to divide an internal core chamber 640 into a plurality of sub-chambers (e.g., the sub-chambers 641-646).

The reactor 603 may include one or more inlets. As shown in FIG. 11, disposed at the first end 631 is a first inlet 633 that is configured to receive a fluidizing gas. Also disposed near the first end 631 is a second inlet 634 that is configured to introduce a feedstock, such as low grade coal, into the reactor 603. For example, the second inlet 634 may be configured to introduce feedstock into a second sub-chamber 642 of the reactor 603. Disposed near the second end 632 is a third inlet 635 that is configured to introduce catalyst (e.g., new catalyst, regenerated catalyst, a combination thereof) into the reactor 603. For example, the third inlet 635 may be configured to introduce catalyst into the sixth sub-chamber 646.

The reactor 603 may include one or more outlets. As shown in FIG. 11, the reactor 603 includes a first outlet 636, which is configured to remove spent catalyst from the reactor, and a second outlet 637, through which upgraded feedstock, such as an upgraded coal product, is recovered. The first outlet 636 may be disposed near the first end 631. For example, the first outlet 636 may be configured to remove spent catalyst from the first sub-chamber 641. The second outlet 637 may be disposed near the second end 632. For example, the second outlet 637 may be configured to remove upgraded coal product and to remove off gases (e.g., pyrolysis product gas and/or fluidization gas) from an outlet sub-chamber that is downstream from the sixth sub-chamber 646. According to another example, the off gas may be outlet via the second outlet 637, such that the upgraded feedstock and off gases exit the reactor 603 together. Thus, the off gases and upgraded feedstock may be separated inside or outside the reactor 603.

As noted above, the reactor 603 may include one or more plate assemblies configured to define the reactor into sub-chambers. As shown in FIG. 11, the reactor 603 includes seven plate assemblies 651-657, which divide the reactor 603 into sub-chambers 641-646, along with an inlet sub-chamber and an outlet sub-chamber. Each plate assembly includes one or more plates. As shown, each of the first and seventh plate assemblies 651, 657 include a single plate configured as a sieve plate with a plurality of apertures in the plate. The size of the apertures may be tailored. According to an exemplary embodiment, the size of the apertures are configured to allow the particles of the feedstock to pass through the apertures, while preventing the particles of catalyst from passing through the apertures. Thus, the sieve plates may separate catalyst and feedstock while the feedstock flows through the reactor from sub-chamber to sub-chamber. The plates of the first and seventh plate assemblies 651, 657 are fixed relative to the housing 630. The second thru sixth plate assemblies 652-656 may be configured to include a sieve plate and a second plate disposed adjacent the sieve plate, where the second plate has an opening disposed in a solid portion. The feedstock may pass through the sieve plate and the opening in the second plate. According to another example, each of the second thru sixth plate assemblies 652-656 include a single plate having a solid portion and a sieve portion, where the sieve portion is configured to restrict the flow of catalyst but allows feedstock to flow through the apertures of the sieve portion. The sieve portion of the second thru sixth plate assemblies 652-656 may be offset from a longitudinal axis 658, such as, for example, in an alternating manner as shown in FIG. 11, where the second, fourth, and sixth sieve plates are on a similar side of the longitudinal axis and the third and fifth sieve plates are on a similar side that is opposite to the side of the second, fourth and sixth sieve plates. This offset arrangement of the sieve portions may advantageously induce an alternating flow of feedstock through the reactor 603, which may create more exposure of the feedstock to the catalyst and increase residence time.

As shown, each of the second thru sixth sub-chambers 642-646 acts as a staged reaction zone, where the feedstock is exposed to catalyst to form an upgraded feedstock as a result of the reaction. The first sub-chamber 641 serves as a disengagement zone, such that the spent catalyst passing through the second plate assembly 652 can be recaptured for regeneration via the outlet 636.

The reactor 603 may be configured to include one or more transfer valves (e.g., bypass valve, slide valve, gate valve, etc.) configured to control the flow through reactor 603. For example, a valve 660 may be provided to control the flow of catalyst between each pair of adjacent sub-chambers. A first valve 660 fluidly connects the first and second sub-chambers 641, 642 by way of a first pipe extending from the first sub-chamber 641 to the valve 660 and a second pipe extending from the second sub-chamber 642 to the valve. Similarly, second, third, fourth, and fifth valves 660 fluidly connect the second and third sub-chambers 642, 643, the third and fourth sub-chambers 643, 644, the fourth and fifth sub-chambers 644, 645, and the fifth and sixth sub-chambers 645, 646 sub-chambers, respectively. Each of the second, third, fourth, and fifth valves 660 include a pipe connecting each sub-chamber with the valve. Each valve 660 is adjustable to change (e.g., increase, decrease) the flow rate through the valve.

A valve may be provided to control the flow through each inlet and/or outlet of the reactor 603. For example, a valve may be provided to control the flow of feedstock through the first inlet 634 and/or the catalyst through the second inlet 635. Also, for example, a valve may be provided to control the flow of spent catalyst through the first outlet 636 and/or the flow of upgraded feedstock through the second outlet 637.

The reactor 603 of FIG. 11 accomplishes many of the desired effects disclosed in this application by manually controlling the solids flow of the more buoyant particles including particles of a solid carbonaceous material feedstock, using transfer valves for controlling the downward flow of the less buoyant particles including catalyst, and preventing upward flow of catalyst by entirely dividing the core chamber into sub-chambers with plate assemblies including plates (e.g., sieve plate, block plate, etc.). In this configuration, there is no open cross-section area allowing complete free flow of solids, since the flow of catalyst particles is restricted. As with a diagonal fluid bed, this reactor is designed to force the more buoyant particle upward, and uses sieves to trap the less buoyant particle in each sub-chamber.

The reactor 603 of FIG. 11 may avoid packing of the catalyst at the bottom by partitioning the reactor into zones (e.g., sub-chambers). The zones may be of variable volume to account for increased gas flow as pyrolysis gas is evolved during the reaction it commingles and flows together and in the same direction with the fluidization gas, increasing the overall amount of gas flow along the length of the reactor. By having plates that are mostly solid, but include sieves in part of the plate designed to let only the feedstock (e.g., coal) pass, the reactor separates the solids (e.g., feedstock, catalyst), which may advantageously eliminate the need for solid-solid separation outside the reactor 603. Preferably, the cross sectional area of the partial sieves creates a local velocity higher than the critical entrainment velocity of the more buoyant particles. More preferably, the cross sectional area of partial sieves can be designed to create local velocities greater than the minimum fluidization velocity of the less buoyant particles, forcing a churning motion. The location of the sieve openings/apertures can be varied from sieve to sieve to force the feedstock through a tortuous path in the reactor. The slide or gate valves may occasionally be opened to allow catalyst to pass downward in the reactor. The frequency may be determined by a coking rate. These could also simply be discharges to a common catalyst collection receptacle. This could also be metered continuously by typical solids metering valves, such as a rotary valve or auger. Advantageously, the lowest sub-chamber (e.g., the first sub-chamber 641) is provided below the coal feed point (e.g., the inlet 634) to allow any entrained coal time to disengage. Advantageously, the disengagement zone may become the regeneration zone, allowing hot flue gas to pass into the pyrolyzer. In this case the fluidizing gas could contain an oxidizing component, such as oxygen. Also, the oxidizing gas may, preferably, be enriched air or oxygen, such as to avoid the system becoming overloaded with nitrogen.

FIG. 12 illustrates another illustrative embodiment of a pyrolysis reactor 703 configured to provide solid-solid reactor of a solid carbonaceous material feedstock and a catalyst. The pyrolysis reactor 703 also provides solid-solid separation of an upgraded solid carbonaceous product and the spent catalyst. In particular, the reactor 703 is configured to utilize a fluidized catalyst (e.g., bubbling bed of catalyst) that is not entrained, as discussed above.

The reactor 703 includes a housing 730 having a first (e.g., lower) section 731 and a second (e.g., upper) section 732. The first section 731 has a generally tubular shape defining an internal lower chamber, and the second section 732 has a generally conical shape defining an internal upper chamber. A frusto-conical intermediate portion may interconnect the first section 731 and the second section 732. The reactor 703 may include one or more than one inlets. A first feed pipe 741 is disposed at an end of the second section 732 and is fluidly connected to a first dipleg 751 extending into a fluidized regime 735. A second feed pipe 742 is disposed at the end of the second section 732 and is fluidly connected to a second dipleg 752 extending into the fluidized regime 735. A feedstock may be introduced into the internal chamber of the reactor 703 through one of the first and second feed pipes 741, 742, while a catalyst may be introduced into the internal chamber via the other of the first and second feed pipes. As shown, the reactor 703 includes a third inlet that is disposed at an end of the first section 731 (e.g., the end opposite the end of the second section 732) and configured to receive fluidization gas from pipe 743. The third inlet is configured to introduce fluidization gas into the internal chamber via a fluidization gas distributer 745. Reference numeral “739” denotes a fluidized bed level (e.g., an adjustable interface of dense bed below with dilute phase solids above).

The reactor 703 may include one or more than one outlet. Also shown in FIG. 12, a first outlet pipe 761 is disposed at the second section 732 (e.g., the end thereof). The first outlet pipe 761 is configured to discharge fluidization gas, pyrolysis product gases and the upgraded carbonaceous product. A second outlet pipe 762 is disposed at the first section 731 (e.g., the end thereof) and configured to discharge the spent catalyst. For example, the second outlet pipe 762 may surround the third inlet and pipe 743. Thus, the upgraded carbonaceous product exits the reactor 703 via the first outlet 761 and the spent catalyst exits the reactor 703 via second outlet pipe 762. In experimental studies of this reactor, we have demonstrated that the reactor can be run such that solids exiting the reactor through exit port 761 contain a weight ratio less than 1 weight part catalyst per 100 parts of carbonaceous product.

Now, a comparison including actual data recovered from a reactor similar to the reactor 703, which was configured to run first as a riser reactor (i.e., Example 1) and then second as a hybrid elutriating riser bed (HERB) reactor (i.e., Example 2), will be discussed. In the first run, the riser reactor was configured to operate providing a partial catalytic pyrolysis of coal. The reactor was configured having a ¾ inch diameter pyrolysis reactor with 8 feet of heated height, which was fed with a coal and catalyst mixture. The reactor also had an unheated disengagement zone, which was approximately 7 feet high×¾ inch diameter, provided above the heated zone. Catalyst and coal entered the reactor from the bottom. Additionally, nitrogen was provided as a fluidization gas via a sparger at the bottom of the reactor. Gases and solids were taken off the top of the reactor where they entered a cyclone separator where solids and gases were separated at the effluent temperature of the pyrolysis reactor. Product gases were then sampled with a gas chromatograph (GC) to determine light components (e.g., components lower than Benzene), and the heavier components were condensed in a liquid trap and then injected into a GC column for quantitative analysis. The spent catalyst and upgraded coal product were weighed to determine catalyst recovery efficiency and coal conversion. The upgraded coal product was analyzed for carbon content, volatile matter, ash, and sulfur. In the embodiments described in this application, we have generally described the catalyst as being larger, denser, or less mobile than the carbonaceous material. This choice is driven by economic rather than technical considerations. The economic drivers favor configuring the catalyst as the larger, denser, or less mobile material because the larger, denser, or less mobile material tends to be handled less and tends to be transported less. Because of the reduced handling, losses will be minimized and as the catalyst is usually more expensive than the carbonaceous material, it is generally better to minimize the catalyst losses. However, it is just as valid to reverse the roles of the catalyst and the carbonaceous material. What is required is differences in densities, sizes, or mobility; which material is larger, denser, or less mobile has no impact on the operability or effectiveness of the process. Therefore, it should be understood that any embodiments specifically referring to the catalyst being larger, less mobile, or denser than the CM, also implicitly disclose configurations where the CM is larger, less mobile, or denser than the catalyst. Commensurately, all locations of the CM and catalyst in process schematics would be inverted as well.

During start-up, the reactor was heated by supplying hot catalyst from an attached heated regenerator vessel which served as the catalyst reservoir during the studies. The catalyst was recirculated between the regenerator vessel and the pyrolysis reactor until a steady state temperature was attained. Catalyst flow was controlled by a gate valve between the regenerator vessel and the pyrolysis reactor. Flow rate was calibrated by gate valve position and weight beforehand, and validated by total weights before and after the run. Once the temperature was attained, coal feed was introduced at the bottom of the pyrolysis reactor via an auger. Feed rate of coal was controlled by the speed of the auger. At the same time, the combined flow of upgraded coal product and spent catalyst from the riser was diverted to a product collection vessel. The run was carried out until the catalyst in the regenerator vessel (reservoir) was depleted.

Process conditions and results are contained in Table 1 (below). Although the experiment ran steady and in control, a number of shortfalls of this configuration were identified. First, as a practical matter, it was difficult to run for extended periods of time, because the catalyst consumption was high. The catalyst came out with the product and had to be separated in another step. Second, it was clear from the results that an optimal contact time for the catalytic pyrolysis reactions was not provided. When compared to results in the smaller lab apparatus (FIGS. 5-7), conversion of coal was low, and yields of all hydrocarbon and fuel products were low.

In the configuration of Example 1, increasing residence time was difficult because it required a decrease in fluidization velocity, which was discovered to result in a loss of entrainment of the catalyst. However, it was determined that upgraded coal product could be successfully separated from catalyst by adjusting fluidization velocity to thereby enable elutriation of the particles of coal to pass through a bubbling bed of catalyst. In the vessel, there was adequate mixing of the coal with catalyst in the lower bubbling bed zone, and because the coal was less dense and smaller in average particle size, the coal would elutriate out of the bed while the catalyst stayed behind. It is postulated that for this to occur, the fluidization velocity was adjusted to an intermediate velocity provided between the two entrainment velocities associated with each of the two particle types, coal and catalyst. This vessel is considered a hybrid reactor, because it acts as a riser with respect to coal flow and a bubbling, fluidized bed with respect to catalyst, while accomplishing an elutriation separation. Thus, this reactor is described as a HERB reactor in this application.

In Example 2, the same reactor configuration as Example 1 was used, but the procedure was modified to enable it to run as a HERB reactor, to carry out partial pyrolysis of coal. First, an 8 feet heated section of the riser was filled with fluidized catalyst. Then the coal was fed into the base of the pyrolyzer. During the run, no fresh catalyst was added.

Despite the differences between Example 1 and Example 2, Example 2 provides a number of advantages over Example 1. First, Example 2 is able to run for much longer extended periods of time, compared to Example 1, while using much less catalyst. Second, Example 2 serves the dual purpose of separating the upgraded coal product from the catalyst in addition to carrying out the catalytic pyrolysis reaction. The results show that very little catalyst escaped the pyrolysis reactor during the run. Without being bound by theory or explanation, it is believed that the most relevant factor in achieving good selectivity and conversion in Example 2, the HERB pyrolysis reactor configuration, is having a high concentration of catalyst in the coal, to promote more favorable conditions for controlled selectivity and conversion. This is supported by the results in Table 1, in which fuels yield increases from 8.43% in Example 1 to 22.80% in Example 2, more valuable fuels (e.g., condensable fuels) increases with the lighter components rising from 3.74% in Example 1 to 7.42% in Example 2, and the most valuable BTEX components rise from 0.29% in Example 1 to 2.18% in Example 2. The results are indicative of effective contacting of the solid carbonaceous feedstock (e.g., coal) with a selective and active catalyst.

It is noted that although on a superficial basis, the residence (i.e., contact) time of the solid carbonaceous material and catalyst in Example 2 is longer than in Example 1 (see line 14 of Table 1), if one corrects for the percent volume of the reactor having catalyst, then a calculated effective contact time of the coal with catalyst is actually lower in Example 2. For example, making such a correction assuming that approximately 76% of the reactor volume is catalyst, the effective contact time of the coal in Example 2 is 0.65 seconds compared to 3.77 seconds in Example 1. Therefore, while we set out to increase contact time with this reactor with the desire of increasing extent of reaction, we in fact, decreased the residence time of coal, and yet surprisingly, the extent of reaction substantially increased. This can be explained in part by the theory that the effective residence time during which the feed coal was in active contact with catalyst was actually higher in Example 2.

TABLE 1 Working parameters of the reactors of Examples 1 and 2 discussed above, along with recovered products according to these two examples. Example 1: Example 2: Riser HERB 1. Run duration, minutes 8.9 70.0 2. Raw coal feed (dry basis), kg 0.269 0.531 3. Upgraded coal product out (dry basis), kg 0.201 0.344 4. Coal feed rate, kg/hr 1.809 0.455 5. Fresh catalyst feed rate, kg/hr (for HERB: initial charge/run time) 11.158 0.325 6. Riser lift gas velocity (in riser, corrected for T P), m/s 1.476 0.895 7. Riser lift gas volumetric flow, m³/s 4.21E−04 2.55E−04 8. Density of coal in reactor, kg/m³ 1.226 0.509 9. Catalyst fluidization state (riser, fluid) riser fluid 10. If fluid, kg of catalyst in reactor N/A 3.81E−01 11. Density of catalyst in reactor, kg/m³ 4.62 548 12. Bulk density of catalyst, kg/m³ 720 720 13. Available void volume % not occupied by catalyst (1-Bulk/Bed 99% 24% density) 14. Coal Residence time, seconds 1.65 2.72 15. Corrected coal residence time based on available void volume 1.64 0.65 16. Catalyst/coal ratio (based on fresh catalyst and coal feeds) 3.77 0.41 17. Catalyst to coal ratio based on bed densities 3.77 1077.46 18. Reactor Average temperature, C. 491.61 494.09 PROCESS PERFORMANCE, ALL VALUES IN KG PRODUCED PER 100 KG OF DRY COAL FEED 19. Raw coal conversion 25.2 35.1 20. Total fuels yield (ex. H₂S), kg per 100 kg 6.89 17.67 21. Total non-condensable fuel gases 3.51 10.38 22. CO 1.80 4.80 23. H₂ 0.02 0.20 24. METHANE 0.61 2.53 25. ETHYLENE 0.85 2.05 26. ETHANE 0.23 0.79 27. ACETYLENE 0.00 0.01 28. LPG: light condensable fuels (ex. BTX and higher 3.19 5.85 hydrocarbons) 29. PROPYLENE 1.66 2.72 30. N-PROPANE 0.18 0.28 31. PROPADIENE 0.00 0.02 32. CYCLOPROPANE 0.00 0.00 33. METHYLACETYLENE 0.00 0.00 34. ISOBUTANE 0.11 0.08 35. ISOBUTYLENE 0.37 0.62 36. 1-BUTENE 0.16 0.28 37. 1,3-BUTADIENE 0.05 0.54 38. N-BUTANE 0.05 0.05 39. TRANS-2-BUTENE 0.16 0.20 40. CIS-2-BUTENE 0.16 0.21 41. CYCLOBUTANE 0.00 0.00 42. ISOPENTANE 0.03 0.03 43. 1-PENTENE 0.09 0.07 44. N-PENTANE 0.03 0.03 45. TRANS-2-PENTENE 0.00 0.07 46. CIS-2-PENTENE 0.06 0.03 47. 2-METHYL-2-BUTENE 0.00 0.09 48. 3-METHYLPENTANE 0.00 0.00 49. 2-METHYLPENTANE 0.00 0.00 50. 1-HEXENE 0.00 0.08 51. N-HEXANE 0.08 0.45 52. 2,3-DIMETHYLPENTANE 0.00 0.00 53. 2-METHYL-1-BUTENE 0.00 0.00 54. BTEX total 0.19 1.43 55. BENZENE 0.11 0.80 56. Toluene 0.08 0.56 57. Xylene 0.00 0.07 58. HIGHER AND HETEROATOM CONTAINING 0.00 0.00 HYDROCARBONS 59. SULFUR GASES 60. H₂S 1.37 2.71 61. SO₂ 0.00 0.00 62. Other sulfur gases 0.18 0.24 FEED COAL ANALYSIS, WT % DRY BASIS 63. Fixed Carbon 30.9 30.9 64. Volatile Matter 34.4 34.4 65. Ash 34.75 34.75 66. Total sulfur 3.9 3.9 67. Pyrite 0.546 0.546 68. Sulfate 0.026 0.026 69. Organic 3.315 3.315

It should be appreciated that this process can be used on a variety of carbonaceous materials with varying amounts of volatile matter, ash, fixed carbon, sulfur, and heating values (often referred to as rank). However, through testing various coals, we have found that even disparate ranks of coal and carbonaceous materials can be compared by looking at conversion and yields based on the feed carbonaceous material.

To better elucidate this point, the following table contains yield calculations and others figures of merit based on the above data. Additionally, we have summarized the ranges observed in all of our continuous reactor runs in the following table, as well as our projected ranges based on our empirical knowledge and based on simulations using mass and energy balances. It should be stressed that these are non-limiting ranges for the practice of the processes/systems of this application.

TABLE 2 Figures of merit in process performance calculated from data in Table 1. Example 1: Example 2: Riser HERB 1. kg of upgraded coal per 100 kg of dry coal feed 74.7 64.8 2. kg of sulfur in upgraded coal per 100 kg of sulfur in coal feed 41.4 35.9 3. kg of ash in upgraded coal per 100 kg of ash in coal feed 97.4 4. kg of fixed carbon in upgraded coal per 100 kg of fixed carbon in 68.1 coal feed 5. kg of volatile matter in upgraded coal per 100 kg of volatile matter in 26.9 28.7 coal feed Hydrocarbon yields based on volatile matter content 6. kg of non-condensable fuels produced per 100 kg of volatile matter in 10.2 30.2 coal feed 7. kg of LPG produced per 100 kg of volatile matter in coal feed 9.3 17.0 8. kg of BTEX per kg of volatile matter in coal feed 0.6 4.2 9. kg of all other hydrocarbons per kg of volatile matter in coal feed — — 10. total kg of all hydrocarbons per kg of volatile matter in coal feed 20.0 51.3 Hydrocarbon selectivities based on volatile matter converted 11. kg of non-condensable fuels produced per 100 kg of volatile matter 14.0 42.3 converted in reaction 12. kg of LPG produced per 100 kg of volatile matter converted in 12.7 23.9 reaction 13. kg of BTEX produced per 100 kg of volatile matter converted in 0.8 5.8 reaction 14. kg of all other hydrocarbons and heteroatoms produced per 100 kg of — — volatile matter converted in reaction 15. total kg of all hydrocarbons per kg of volatile matter converted in 27.4 72.0 reactor 16. HHV fuel value of input coal, as received, MJ/kg 12.8 12.8 17. HHV fuel value of output coal, as received, MJ/kg 13.7 14.7 18. Upgrade factor: HHV of output coal/HHV input coal (as received 1.07 1.15 basis) 19. Weight hour space velocity, (kg/hr dry coal feed)/(kg catalyst) 3.93 1.07

TABLE 3 Ranges in figures of merit in process performance observed in continuous runs (both HERB and riser configurations), and projected based on lab data, continuous runs, and simulations based on mass and energy balances. Range in Expected continuous coal ranges feed reactors (inclusive) 1. kg of upgraded CM per 100 kg of dry CM feed 55-100 40-100 2. kg of sulfur in upgraded CM per 100 kg of sulfur in CM feed 25-79  0-80 (overall) 0-50 (organic) 50-100 (pyritic) 0-50 (sulfate) 3. kg of ash in upgraded CM per 100 kg of ash in CM feed 93-100 60-100 4. kg of fixed carbon in upgraded CM per 100 kg of fixed carbon 61-100 50-100 in CM feed 5. kg of volatile matter in upgraded CM per 100 kg of volatile 23-73  0-90 matter in CM feed Hydrocarbon yields based on volatile matter content 6. kg of non-condensable fuels produced per 100 kg of volatile 1-39 0-40 matter in CM feed 7. kg of LPG produced per 100 kg of volatile matter in CM feed 1-21 0-40 8. kg of BTEX per kg of volatile matter in CM feed 0-9  0-40 9. kg of all other hydrocarbons per kg of volatile matter in CM 0-0  0-20 feed 10. total kg of all hydrocarbons per kg of volatile matter in CM feed 2-62 10-90  Hydrocarbon selectivities based on volatile matter converted 11. kg of non-condensable fuels produced per 100 kg of volatile 1-42 0-60 matter converted in reaction 12. kg of LPG produced per 100 kg of volatile matter converted in 1-23 0-60 reaction 13. kg of BTEX produced per 100 kg of volatile matter converted in 0-9  0-60 reaction 14. kg of all other hydrocarbons and heteroatoms produced per 100 kg 0-0  0-40 of volatile matter converted in reaction 15. total kg of all hydrocarbons per kg of volatile matter converted 2-71  2-100 in reactor 16. Upgrade factor: HHV of output solid material/HHV input solid 1.04-1.62  0.9-1.80 material (as received basis) 17. Weight hour space velocity, (kg/hr dry coal feed)/(kg catalyst) 0.31-12.5  0.2-20   18. Catalyst to coal feed ratio, (kg/hr dry catalyst feed)/(kg/hr coal 0.08-72    0-100 feed) 19. kg of CO₂ produced per 100 kg of dry coal feed 1-20 1-25 20. kg of CO₂ produced per 100 kg of volatile matter feed 2-57 2-65

These figures of merit are illustrative of the unique ability of this processes/systems of this application to carry out upgrading of carbonaceous materials while providing beneficial materials and in process that has superior operability to prior methods. Further explanation of the significance in reference to row numbers is as follows:

Row 2 is a measure of the weight fraction of sulfur retained in upgraded CM. This process reduces the sulfur in upgraded CM. Without wishing to be bound by any theory or explanation, our results suggest that organic sulfur and sulfates in the carbonaceous material is liberated as hydrogen sulfides, and only pyritic sulfur is retained. We expect the pyritic sulfur to stay with the ash, so the retention of pyritic sulfur to be similar to the ash retention in the upgraded CM.

Row 3 is a measure of the weight fraction of ash retained in the upgraded carbonaceous material. This process is unique in that most of the ash in the carbonaceous material is retained in the carbonaceous material. This is a key advantage of this process: very little ash is free to sorb on the catalyst and clog the catalyst pores. Ash accumulation on catalyst is a known irreversible deactivation mechanism of most pyrolysis catalysts, so our process will suffer less from this problem.

Row 4 is a measure of the weight fraction of fixed carbon retained in the upgraded carbonaceous material. Most, and in many cases, all, of the fixed carbon is retained in the upgraded carbonaceous product. Fixed carbon is known to be difficult to pyrolyze, particularly at the temperatures of this process, so without being bound to any particular theory or explanation, we believe that the fixed carbon not retained in the upgraded carbonaceous material is either oxidized by oxygen in the CM, or becomes coke on the catalyst. In other words, no fixed carbon is transformed into hydrocarbon products.

Row 5 is a measure of the weight fraction of volatile matter retained in the upgraded carbonaceous material. Without being bound to any particular theory or explanation, we believe that the volatile matter is the major source for all hydrocarbons liberated in this process because the fixed carbon is much more difficult to pyrolyze. As can be seen from our experimentally observed ranges, we typically retain some portion of the volatile matter. However, we chose to keep some volatile matter in the product coal because our desired end product in these experiments was a coal that can be efficiently burned in a boiler. (A coal that is efficiently burned in a boiler is often referred to as a “steam coal”). Steam coals require some volatile matter so that they may be easily ignited. Without volatile matter, a coal will not burn efficiently. However, coals with low volatile matter are often useful as coking coals, used in steelmaking. Our process may be run at more aggressive conditions (e.g., higher temperature, residence time) to convert most or all of the volatile matter giving a coking coal, suitable for use in steelmaking.

In rows 6-10, we recalculate fractional yields by weight based on volatile matter in the CM rather than the total CM weight. Based on our non-limiting working theory, we believe that as most of the hydrocarbons come from the volatile matter, it makes sense to base yields and selectivities on volatile matter content. We have seen that this allows us to predictably compare performance across various ranks of carbonaceous feedstocks.

In rows 11-15, we calculate fractional selectivities by weight based on volatile matter converted in the process. The total selectivity to hydrocarbons (Row #15) is a good measure of how effective the process is at utilize the converted volatile matter. A perfect process would approach 100%. It can readily be seen the effectiveness of running the reactor in the HERB configuration, as over 70% of the converted volatile matter yields hydrocarbons.

In row 16, we calculate an upgrade index. This upgrade index is defined as the ratio of the heating value of the upgraded carbonaceous product and the heating value of the feed carbonaceous material (on an as received basis). A number of factors determine this index, and although we often increase the heating value, it is not necessarily a higher value because a number of factors move the value in opposite directions. For example, nearly all of the moisture is removed from the feed material. This will increase the heating value and increase the efficiency in a boiler. Also, for example, much of the volatile matter is removed from the feed material. Depending on the relative heating value of the volatile matter to the remainder of the components in the CM, this can either increase or decrease the product's heating value. For example, if the ash content is high in the feed material, the non-volatile contents in the CM (Fixed Carbon+Ash) will be low relative to the volatile matter, so reduction in volatile matter will reduce heating value. Also, for example, most of the oxygen is removed from the feed material. This has the effect of increasing the heating value of the product relative to the feed material. Based on the above factors, we would expect a higher upgrade index for carbonaceous feedstocks with high oxygen, high moisture, and low ash, and vice versa.

In rows 19 and 20 (of Table 3), it should be noted that the CO₂ production may vary depending on the type of carbonaceous matter used.

Now, an illustrative product composition of a mild catalytic pyrolysis reactor will be described. An illustrative result of the pyrolysis reactor is presented in Table 4 (below). The product composition is based on an analysis of experimental laboratory results of a low-grade coal catalytically pyrolyzed at 400° C. using a zeolite catalyst. Approximately 45% of the volatile matter was converted to gaseous, liquid, and upgraded solid product, such as upgraded coal product. The level of conversion may be tailored (e.g., increased, reduced), such as by increasing or reducing the reaction temperature and/or reactor residence time. The usable products contain valuable olefins and aromatics. The results of the catalytic pyrolysis showed no compounds larger than C₁₂, indicating that little or no tar or other highly viscous material handling would be necessary if this catalytic pyrolysis reaction was scaled-up to a larger commercial size and practiced precisely as it was in the small-scale lab experiment.

TABLE 4 Estimated chemical composition of product (hydrocarbons only) for low-grade coal sample catalytically pyrolyzed with a zeolite catalyst. Carbon # Weight % Category Weight % C₁ 8.55 Paraffins 25.73 C₂ 12.19 Olefins 42.59 C₃ 27.97 Aromatics 26.80 C₄ 14.56 Oxygenated 4.88 C₅ 1.70 hydrocarbons C₆ 3.45 C₇ 10.47 C₈ 14.30 C₉ 1.01 C₁₀ 2.98 C₁₁ 0.59 C₁₂ 2.23

Now, the results of experiments using an experimental test setup are shown, graphically, in FIGS. 5-7. The experimental system included a fluidized bed reactor. FIG. 5 compares the yields of various compounds including lower molecular weight hydrocarbons of the system using a catalyst and sand at 400° C. FIG. 6 compares the yields of various compounds including lower molecular weight hydrocarbons from the system using a catalyst at 400° C., sand at 400° C., and the catalyst at 600° C. FIG. 7 compares the yields of various compounds from the system using a catalyst at 400° C., sand at 400° C., and the catalyst at 600° C.

The systems and processes, as disclosed herein, may be integrated with other industrial applications. Examples of such industrial applications include, but are not limited to, coal-fired power generation facilities (e.g., plants), gas to liquid (GTL) facilities, coal/coke/biomass gasification (CCBG) facilities, blast furnace (BF) facilities, and oil refining and/or steam cracking facilities. Coal-fired power generation facilities may serve as an outlet for waste heat from the systems, excess steam from the systems, fuel gas for a co-firing boiler, fuel gas use as staged NO_(x) reduction (e.g., rich reagent injection, as a so-called “reburn” stream, etc.), and/or upgraded coal to a boiler. GTL facilities may be used with the systems to upgrade lower value fuel gas and/or other hydrocarbons, especially light hydrocarbons (e.g., C₁-C₄), into other higher value useful heavier liquid hydrocarbons (e.g., liquid transportation fuels) by any suitable method. For example, GTL facilities may be used with the systems to convert the hydrocarbons into syngas and syngas into Fischer-Tropsch liquids, to convert syngas into methanol and methanol into gasoline, as an oligomerizer of light olefins, such as ethylene-propylene-butylene, into gasoline range hydrocarbons, for the alkylation of iso-butylene with butane to form iso-octane fuel additive, as well as for other conversions. CCBG facilities may serve as an outlet for waste heat from the systems, excess steam from the systems, fuel gas for co-feeding to a gasifier, upgraded coal as feed to a gasifier, fuel gas as co-feed to raw synthesis gas (e.g., supply of H₂ and CO), and/or fuel gas and hydrocarbons to steam reforming to supply additional H₂/CO. BF facilities could use upgraded coal from the systems as a substitute for metallurgical coke feed or as a pulverized coal injection (PCI) feed in the facility. Oil refining and/or steam cracking facilities may serve as an outlet for waste heat and/or excess steam from the systems, as well as with hydrocarbon and fuel gas feeds for production of hydrogen, CO, methane, ethane, ethylene, propane, propylene, butanes, butenes, pentanes, pentenes, and all of their derivatives including fuels, solvents, monomers, polymers, specialty chemicals and large arrays of refined products.

Now, a calculated example of a process according to one embodiment will be described. The following embodiment includes a coal beneficiation plant integrated at a pulverized coal-fired power plant. For this example, the coal beneficiation plant is designed to use a North Dakota lignite coal for a nominal 50 tons/hour raw coal capacity. The ultimate and proximate analysis for the North Dakota Lignite coal is presented in Table 5 (Kitto & Stultz, 2005).

TABLE 5 Coal analysis for North Dakota Lignite coal (Kitto & Stultz, 2005): Original North Dakota Lignite Proximate (Wt %) Moisture 33.3 VM (Dry) 43.6 FC (Dry) 45.3 Ash (Dry) 11.1 Heating Value (Btu/lb) As Received 7,090 Ultimate (Dry Wt %) C 63.3 H 4.5 N 1 S 1.1 O 19 Ash 11.1

For the calculated example, a system as shown in FIG. 2 utilizing recirculated gas (e.g., methane) into the pyrolysis reactor, was used in the calculations. The beneficiation system was calculated using a low-ranked coal as the solid carbonaceous material to produce one or more usable products. The low-ranked coal enters the pulverizer, where its particle size is reduced to an appropriate size distribution. Air is introduced into the pulverizer to move the coal within the pulverizer and to remove some of the moisture from the coal. As an example, the pulverized coal exiting the pulverizer may have a moisture content of about 29%. To further reduce the moisture content of the coal, the coal is separated from the pulverizer air and then transferred to the dryer, such as through a pipe, where the coal is dried by hot air until its moisture content is about 3%. Thus, air may be passed through the dryer to dry the coal. The system may be configured to utilize flue gas from the catalyst regenerator to either directly or indirectly dry the pulverized coal. The system may be configured to utilize hot flue gas that is generated by burning fuel to either directly or indirectly dry the pulverized coal. The coal may be separated from the gas prior to the coal being transferred to the pyrolyzer (e.g., the catalytic pyrolysis reactor).

The coal enters the pyrolyzer, wherein regenerated catalyst and fresh catalyst are fluidized with the coal with sufficient residence time for the pyrolysis to reach the desired extent of the reaction at about 400° C. In one example, 45% of the volatile matter in the coal is converted to the gaseous product composition similar to the results in the experimental example discussed above. All, or nearly all, of the remaining moisture in the coal is removed in the pyrolysis reactor. All, or nearly all, of the sulfur in the coal is converted to H₂S, COS, and SO₂, resulting in the upgraded coal having a significantly lower sulfur content. A methane loop may be utilized to fluidize the particles inside the pyrolysis reactor and carry the solids and gas products out of the reactor. The solid stream is first separated from the gas stream, and then is further separated into a predominantly upgraded coal stream and a predominantly spent (e.g., deactivated) catalyst stream. The catalyst in the reactor is deactivated, mainly through coke deposition on the catalyst. A classifier may be utilized to separate the solid products into an upgraded coal stream and a stream of spent catalyst.

The upgraded coal product, which generally is in powder form, may be transported for further processing to convert the coal powder into an easily transportable product (such as pellets or briquettes). The upgraded coal may also be injected into the boiler for combustion and steam generation purposes. Because of the quality of the upgraded coal, the upgraded coal burns cleaner and more efficiently than the original raw coal introduced into the pulverizer (e.g., the low-ranked coal). The upgraded coal has a higher heating value, which according to one example is about 11,760 Btu/lb (as compared to 7,090 Btu/lb) and a production rate of 24.2 tons/hour. The coal properties (which have been calculated) are presented in Table 6, provided below. In this example, the upgraded coal retains over 80% of its original heating value while the majority of the remaining heating value is in the gaseous and liquid product.

TABLE 6 Expected coal analysis for the upgraded coal. Upgraded North Dakota Lignite Proximate (Wt %) Moisture 0.0 VM (Dry) 27.0 FC (Dry) 56.5 Ash (Dry) 16.5 Heating Value (Btu/lb) As Received 11,760 Ultimate (Dry Wt %) C 65.7 H 4.53 N 1.24 S 0.62 O 11.4 Ash 16.5

The predominantly spent catalyst stream is transferred to the regenerator through an inlet, while air is introduced into the regenerator through a second inlet. In this calculated example, the spent catalyst has about 5% carbon by weight from the coking. Also, the solid-solid separation results in the spent catalyst stream having less than about 3% of the upgraded coal in the spent catalyst. The air burns the coke off of the spent catalyst at about 600° C. in the regenerator. It is expected that any upgraded coal entering the regenerator with the spent catalyst will be fully combusted, leaving only the coal ash and the regenerated catalyst. The exiting gas stream from the regenerator is a flue gas with approximately 4% oxygen, a level which promotes nearly complete combustion of all carbonaceous material entering the regenerator, including the coke on the spent catalyst. The flue gas has approximately 20% CO₂ by volume. The gas and solids exit separately from the regeneration reactor. A small amount of the regenerated or recycled catalyst stream (e.g., about 3% or less) may be purged through a purging device that is fluidly connected to an outlet of the regenerator. The purged catalyst stream prevents accumulation of coal ash in the catalyst recirculation loop. The remaining recycled or regenerated catalyst stream may be transferred to other elements in the system, such as, for example, the pyrolyzer through a recycled catalyst stream input.

The pyrolyzer may also be configured to utilize a fresh amount of catalyst (i.e., non-recycled or regenerated catalyst) to maintain the desired catalyst-to-coal ratio. The fresh catalyst is introduced into the pyrolyzer through an inlet, and the amount of fresh catalyst may be metered or controlled to maintain the catalyst-to-coal ratio in the pyrolyzer.

Based on the calculated data presented in FIG. 5, at 400° C., the expected final gaseous and liquid product streams out of the pyrolysis reactor and downstream separation units for this 50 ton/hr coal input are:

Non-condensable Fuel Gas 1,100 lb/hr Butane/LPG 580 lb/hr BTEX 940 lb/hr Higher Hydrocarbons 2,800 lb/hr Solid sulfur 390 lb/hr CO₂ (CCS quality) 9,400 lb/hr Non-condensable gas 800 lb/hr

Another system may involve flue gas pyrolysis fluidization, in which all or a portion of the flue gas from the regeneration reactor may be used to fluidize the pyrolysis reactor. Preferably, enough flue gas will be used to provide any necessary heat for the pyrolysis reactor and to help fluidize the coal and catalyst, as well as the carrier gas for the gaseous product out of the pyrolysis reactor. With air fed into the regeneration reactor, the flue gas will consist mainly of a combination of N₂, H₂O, CO₂, CO, and SO₂. Any one or more of O₂, hydrogen, CO₂, CO and/or steam could be used in the regeneration of the catalyst. Alternatively, flue gas from the regenerator may be kept separate from the pyrolysis reactor.

In general, CO₂ capture and purification is more difficult if CO₂ is present in dilute quantities, such as in the presence of nitrogen gas, and/or in the presence of trace amounts of oxygen, such as in a flue gas. As such, the required process equipment for CO₂ capture and purification is larger when CO₂ is contaminated with nitrogen and oxygen gases. And many processing systems, (e.g., acid gas recovery systems) cannot recover CO₂ when it is too dilute. In the systems and processes, as disclosed herein, a high concentration of substantially nitrogen-free and oxygen-free CO₂ is produced in the pyrolysis reactor. Therefore, an acid gas removal system dedicated only to capturing the CO₂ from the pyrolysis reactor will have relatively smaller equipment, and more recovery technology options may be employed by this system, than would otherwise be the case if the regenerator was air fired and if the resultant nitrogen and oxygen laden flue gases from the regenerator were commingled with pyrolysis gases.

It should be noted that although coal has been discussed as an example of a carbonaceous material for use as a feedstock in the systems and the processes described in this application, other suitable materials can be used in the systems and processes. For example, other types of coals that may be used as feedstock in the systems and processes described in this application include but are not limited to lignite or brown coals, sub-bituminous, bituminous, anthracite, peat, or any combination thereof. Coal derived liquids or oils including but not limited to pyrolysis derived oils, oily coal slurry, coking derived oils, gasification derived oils, hydrogenation derived oils, or any combination thereof may be used as feedstock. Tar sands including but not limited to raw tar sands, tar sand derived liquids, asphalt, bitumen, or any combination thereof may be used as feedstock. Oil shale including but not limited to raw oil shale, oil shale derived liquids, kerogen, or any combination thereof may be used as feedstock. Waste oils including but not limited to cooking oils, motor oils, etc., as well as combinations thereof may be used as feedstock. Municipal waste, such as solid waste or waste water treatment sludge, may be used as feedstock. Waste plastics, such as recycled plastics, may be used as feedstock. Biomass including but not limited to lignocellulosic biomass (e.g., various agricultural residues, wheat and rice straw, corn stover, forestry residues, saw dust, wood chips and bark, etc.), lignocellulosic biomass derived oils (e.g., pyrolysis derived oils, hydropyrolysis oils, biocrude, etc.), various lipid containing oils (e.g., plant derived lipid oils, jatropha, palm, algal derived lipid oils, etc.), and combinations thereof may be used as feedstock. Petroleum including but not limited to various petroleum derived oils, crude oil, refinery derived oil, asphalt, synthetic crude oil, bottom oils, residual oils, heavy oils, and combinations thereof may be used as feedstock. Other suitable materials may be used as feedstock as well. Preferably, the carbonaceous raw material releases volatile matter when exposed to thermal pyrolyzation conditions (e.g., heated to pyrolysis temperatures). Less suitable carbonaceous materials would include those such as coke, which has been substantially depleted of volatile matter content. Moreover, any of the feedstocks mentioned above may be used independently or as a co-feed (e.g., co-fed feedstock) with one or more other feedstocks, which may be taken from the feedstocks mentioned above.

Para. A. A process for upgrading a solid carbonaceous material, comprising: heating the solid carbonaceous material in the presence of a catalyst under partial pyrolysis conditions, and obtaining an upgraded solid carbonaceous product, a gaseous product, and a spent catalyst.

Para. B. The process of Para. A, wherein the solid carbonaceous material is coal and the upgraded solid carbonaceous product is an upgraded coal product.

Para. C. The process of Para. A or B, wherein a weight of fixed carbon retained in the upgraded solid carbonaceous product is at least 50 weight percent of fixed carbon in the solid carbonaceous material.

Para. D. The process of any one of Paras. A-C, wherein a weight of ash retained in the upgraded solid carbonaceous product is at least 60 weight percent of ash in the solid carbonaceous material.

Para. E. The process of any one of Para. A-D, wherein a weight of volatile matter retained in the upgraded solid carbonaceous product is from about 10 to about 90 weight percent of volatile matter in the solid carbonaceous material.

Para. F. The process of any one of Para. A-E, wherein a weight of volatile matter retained in the upgraded coal product is from about 10 to about 90 weight percent of volatile matter in the coal.

Para. G. The process of any one of Para. A-F, further comprising pretreating the starting solid carbonaceous material prior to heating under partial pyrolysis conditions using at least one of a dryer, a de-asher, and a washer.

Para. H. The process of any one of Para. A-G, further comprising obtaining an amount of CO₂ greater than about 10 weight % of the volatile matter in the starting solid carbonaceous material.

Para. I. The process of any one of Para. A-H, further comprising separating the gaseous product from the upgraded solid carbonaceous product.

Para. J. The process of any one of Para. I, further comprising condensing the separated gaseous product into a gaseous stream and a liquid stream.

Para. K, The process of any one of Para. A-J, further comprising obtaining an amount of a non-condensable fuel gas from about 1 to about 40 weight % of the volatile matter in the starting solid carbonaceous material.

Para. L. The process of any one of Para. A-K, further comprising obtaining an amount of a non-condensable fuel gas from about 1 to about 40 weight % of the volatile matter in the starting coal.

Para. M. The process of any one of Para. A-L, further comprising obtaining an amount of LPG greater than from about 1 to about 40 weight % of the volatile matter in the starting solid carbonaceous material.

Para. N. The process of any one of Para. A-M, further comprising obtaining an amount of BTEX from about 0.5 to about 40 weight % of the volatile matter in the starting solid carbonaceous material.

Para. O. The process of any one of Para. A-N, further comprising obtaining an amount of Higher Hydrocarbons from about 0.3 to about 20 weight % of the volatile matter in the starting solid carbonaceous material.

Para. P. The process of any one of Para. A-O, further comprising obtaining an amount of heteroatom-containing organics that is no greater than 5 weight % of the volatile matter in the starting solid carbonaceous material.

Para. Q. The process of any one of Para. A-P, wherein the spent catalyst and the upgraded solid carbonaceous product are recovered as a mixture.

Para. R. The process of any one of Para. A-Q, wherein the spent catalyst and the upgraded solid carbonaceous product are recovered separately.

Para. S. The process of any one of Para. A-R, further comprising regenerating the spent catalyst by contacting the spent catalyst with a mixture of gases containing at least one oxidizing gas to form a regenerated catalyst.

Para. T. The process of any one of Para. S, wherein at least a portion of the regenerated catalyst is heated in the presence of additional solid carbonaceous material in a subsequent partial pyrolysis reaction.

Para. U. The process of any one of Para. A-T, further comprising regenerating the spent catalyst by acid washing the spent catalyst with an acidic solution to form a regenerated catalyst.

Para. V. The process of any one of Para. S-U, wherein at least a portion of the regenerated catalyst is heated in the presence of additional solid carbonaceous material in a sub sequent partial pyrolysi s reaction.

Para. W. The process of Para. A-V, wherein a weight of total sulfur retained in the upgraded solid carbonaceous product is no more than 80 weight percent of the total sulfur in the starting solid carbonaceous material.

Para. X. The process of any one of Para. A-V, wherein a weight of organic sulfur retained in the upgraded solid carbonaceous product is no more than 50 weight percent of the organic sulfur in the starting solid carbonaceous material.

Para. AA. A process for converting a solid carbonaceous material in a beneficiation system into a upgraded solid carbonaceous product, the process comprising:

-   -   introducing the solid carbonaceous material and a catalyst into         a pyrolysis reactor to produce a gaseous product stream and a         solid product stream, wherein the solid product stream comprises         the upgraded solid carbonaceous product;     -   recovering the gaseous product stream from the reactor; and     -   recovering the solid product stream from the reactor.

Para. AB. The process of Para. AA, wherein the solid carbonaceous material is coal and the upgraded solid carbonaceous product is an upgraded coal product.

Para. AC. The process of any one of Para. AA-AB, wherein the catalyst is immobilized in the pyrolysis reactor; and the process further comprises separating the upgraded solid carbonaceous product from the catalyst inside the pyrolysis reactor.

Para. AD. The process of any one of Para. AA-AC, further comprising:

-   -   recovering a separated spent catalyst from the pyrolysis         reactor;     -   transferring the spent catalyst to a regenerator; and     -   regenerating the spent catalyst in the regenerator, in which         unpyrolyzed coal, coke, and carbonaceous material are removed         from the spent catalyst.

Para. AE. The process of any one of Para. AA-AD, further comprising:

-   -   transferring the gaseous product stream to a separator; and     -   at least partially condensing the gaseous product stream in the         separator     -   producing a refined gas stream, a hydrocarbon liquid stream, and         an aqueous liquid phase stream.

Para. AF. The process of any one of Para. AA-AE, wherein the solid product stream further comprises a spent catalyst, the process further comprising:

-   -   separating the solid product stream into the upgraded solid         carbonaceous product and the spent catalyst after recovering the         solid product stream from the pyrolysis reactor, wherein the         separated spent catalyst comprises the catalyst and at least one         of unpyrolyzed coal, coke, and carbonaceous material.

Para. AG. The process of Para. AF, further comprising:

-   -   transferring the separated catalyst to a regenerator in which at         least a portion of the at least one of the unpyrolyzed coal,         coke, and carbonaceous material is removed from the catalyst;         and     -   transferring the gaseous product stream to a separator in which         the gaseous product stream is at least partially condensed in         the separator producing a refined gas stream, a hydrocarbon         liquid stream, and an aqueous liquid phase stream.

Para. AH. The process of any one of Para. AA-AG, wherein at least a portion of the at least one of the unpyrolyzed coal, coke, and carbonaceous material is removed from the catalyst by at least one of combustion, steam, and a reducing gas.

Para. AI. The process of any one of Para. AA-AH, wherein the pyrolysis reactor is configured as one of a HERB, a fluidized bed, a moving bed, or an entrained flow bed, and wherein the coal and the catalyst move through the pyrolysis reactor.

Para. AJ. The process of any one of Para. AA-AI, wherein the solid product stream is transferred outside the pyrolysis reactor to a solid-solid separator that separates the upgraded solid carbonaceous product and the spent catalyst.

Para. AK. The process of any one of Para. AA-AJ, wherein the solid-solid separator includes a classifier that separates the upgraded solid carbonaceous product from the spent catalyst based on one of particle size, mass, or density.

Para. AL. The process of any one of Para. AA-AK, wherein at least one of a size and a density of the spent catalyst is different than at least one of a size and a density of the upgraded solid carbonaceous product, and wherein the classifier of the solid-solid separator separates the upgraded solid carbonaceous product and the spent catalyst based on at least one of size and density.

Para. AM. The process of any one of Para. AA-AL, further comprising:

-   -   reducing a size of the particles of the solid carbonaceous         material in a pulverizer prior to being introduced into the         pyrolysis reactor; and     -   pretreating the solid carbonaceous material in a pretreating         device that includes at least one of a dryer configured to dry         the coal from the pulverizer utilizing a stream of heated fluid,         a washer configured to wash the coal from the pulverizer, and a         de-asher configured to remove ash from the coal, wherein the         pretreating device is provided between the pulverizer and the         pyrolysis reactor.

Para. AN. The process of any one of Para. AM, wherein the stream of heated fluid is hot flue gas produced by a regenerator during removal of at least a portion of any unpyrolyzed coal, coke, and carbonaceous material from the spent catalyst utilizing an oxygen-carrying gas.

Para. AO. The process of any one of Para. AE-AN, wherein the separator further includes an acid gas removal system that separates at least one of a sulfur-carrying compound, a nitrogen-carrying compound, and carbon dioxide from the gaseous product stream.

Para. AP. The process of any one of Para. AA-AO, wherein the catalyst introduced into the pyrolysis reactor includes a first portion comprising regenerated catalyst received from a regenerator and a second portion comprising new catalyst that has not been regenerated, and wherein the first portion of regenerated catalyst has a higher relative temperature than the new catalyst and the coal, such that the regenerated catalyst is a heating medium to heat the coal introduced into the pyrolysis reactor.

Para. AQ. The process of any one of Para. AA-AP, wherein the catalytic pyrolysis of the solid carbonaceous material takes place at a temperature from about 350° C. to about 850° C.

Para. AR. The process of any one of Para. AA-AQ, wherein the solid carbonaceous material introduced into the pyrolysis reactor has a weighted hour space velocity from about 0.2 to about 25 kg/hr per kg of catalyst.

Para. AS. The process of any one of Para. AA-AR, wherein the solid carbonaceous material has a residence time during the catalytic process from about 0.1 second to about 1 minute.

Para. AT. The process of any one of Para. AA-AS, wherein a weight ratio of the catalyst to solid carbonaceous material introduced into the pyrolysis reactor is from about 0 to about 100.

Para. AU. The process of any one of Para. AA-AS, further comprising:

-   -   providing an acid gas removal system that is configured to         capture and isolating CO₂ from at least one of the gaseous         product from the pyrolysis reactor and a gas from a regenerator         configured to regenerate spent catalyst from the pyrolysis         reactor; and     -   obtaining an amount of CO₂ greater than about 4 weight % of the         dry ash free coal.

Para. AV. The process of any one of Para. AA-AU, further comprising obtaining an amount of CO₂ greater than about 10 weight % of the volatile matter in the starting solid carbonaceous material.

Para. AW. The process of any one of Para. AA-AV, further comprising obtaining an amount of CO₂ greater than about 4 weight % of the dry ash free coal.

Para. AX. The process of any one of Para. AA-AW, further comprising:

-   -   regenerating a spent catalyst in a regenerator configured to         produce a hot flue gas during regeneration; and     -   transferring at least a portion of the hot flue gas to the         pyrolysis reactor to fluidize the pyrolysis reactor.

Para. AY. The process of any one of Para. AX, wherein a gaseous fluid comprising at least one of CO, CO₂, water, hydrogen, and oxygen is introduced into the regenerator to facilitate removal of unpyrolyzed coal, coke, and carbonaceous material from the spent catalyst.

Para. AZ. The process of any one of Para. AY, further comprising collecting the hot flue gas that includes CO₂ for one of carbon sequestration or enhanced oil recovery.

Para. BA. The process of any one of Para. AX-AZ, further comprising passing the hot flue gas through a heat exchanger to produce heat that is used to heat the solid carbonaceous material in the pyrolysis reactor.

Para. BB. The process of any one of Para. AX-BA, wherein the regenerator uses steam in addition to, or instead of, air to remove the coal, coke, and carbonaceous material from the spent catalyst by at least one of hydrolysis and steam gasification.

Para. BC. The process of any one of Para. AX-BB, wherein the regenerator uses hydrogen or at least one other hydrogen-containing chemical, including hydrocarbons, to reductively remove the coal, coke, and carbonaceous material from the spent catalyst.

Para. BD. The process of any one of Para. AA-BC, wherein a gas is co-fed into the pyrolysis reactor, wherein the gas comprises at least one light hydrocarbon compound that is recovered from the gaseous product stream.

Para. BE. The process of any one of Para. AA-BD, wherein the at least one light hydrocarbon compound is recycled back to the pyrolysis reactor.

Para. BF. The process of any one of Para. AA-BE, further comprising obtaining an amount of BTEX from about 0.5 to about 80 weight % of the volatile matter in the starting solid carbonaceous material.

Para. BG. The process of any one of Para. AA-BF, wherein a biomass is co-fed into the pyrolysis reactor.

Para. BH. The process of any one of Para. AA-BG, wherein at least one of an oil shale, a coal derived liquid, a tar sand, and a petroleum is co-fed into the pyrolysis reactor.

Para. BI. The process of any one of Para. AA-BH, wherein at least one of a wet gas and a natural gas is co-fed into the pyrolysis reactor.

Para. BJ. The process of any one of Para. AA-BI, wherein the pyrolysis reactor includes a stationary catalyst, such that the solid carbonaceous material moves relative to the catalyst through the reactor, to produce the gaseous product stream and the solid product stream, the process further comprising:

-   -   transferring the gaseous product stream to a separator to at         least partially condense at least a portion of the gas product         stream into a liquid product and a gaseous product; and     -   wherein the solid product stream contains less than 1 weight         part catalyst per 100 parts upgraded carbonaceous product.

Para. CA. A process for converting a biomass in a beneficiation system into an upgraded solid product, the process comprising:

-   -   introducing the biomass and a catalyst into a pyrolysis reactor         to produce a gaseous product stream and an upgraded solid         product stream, the solid product stream comprising spent         catalyst and the upgraded solid product;     -   separating the upgraded solid product and the spent catalyst;     -   transferring the separated spent catalyst to a regenerator that         removes at least a portion of any unpyrolyzed coal, coke, and         other carbonaceous material from the spent catalyst; and     -   transferring the gaseous product stream to a separator that         produces a liquid product and a gaseous product;     -   wherein a weight of ash retained in the upgraded solid product         is at least 60 weight percent of ash in the biomass introduced         into the pyrolysis reactor.

Para. CB. The process of Para. CA, wherein an amount of phenol produced is less than an amount of toluene produced on a weight basis.

Para. CC. The process of Para. CA or CB, wherein an amount of tars produced is less than an amount of light oils produced on a weight basis.

As utilized herein, the terms “approximately,” “about,” “substantially”, and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and claimed are considered to be within the scope of the invention as recited in the appended claims.

The terms “coupled,” “connected,” and the like, as used herein, mean the joining of two members directly or indirectly to one another. Such joining may be stationary (e.g., permanent) or moveable (e.g., removable or releasable). Such joining may be achieved with the two members or the two members and any additional intermediate members being integrally formed as a single unitary body with one another or with the two members or the two members and any additional intermediate members being attached to one another.

References herein to the positions of elements (e.g., “top,” “bottom,” “above,” “below,” etc.) are merely used to describe the orientation of various elements in the FIGURES. It should be noted that the orientation of various elements may differ according to other illustrative embodiments, and that such variations are intended to be encompassed by the present disclosure.

The construction and arrangement of the elements of the systems (e.g., beneficiation systems) as shown in the illustrative embodiments are illustrative only. Although only a few embodiments of the present disclosure have been described in detail, those skilled in the art who review this disclosure will readily appreciate that many modifications are possible (e.g., variations in sizes, dimensions, structures, shapes and proportions of the various elements, values of parameters, mounting arrangements, use of materials, colors, orientations, etc.) without materially departing from the novel teachings and advantages of the subject matter recited. For example, elements shown as integrally formed may be constructed of multiple parts or elements, the position of elements may be reversed or otherwise varied, and the nature or number of discrete elements or positions may be altered or varied.

Additionally, the word “illustrative” is used to mean serving as an example, instance, or illustration. Any embodiment or design described herein as “illustrative” is not necessarily to be construed as preferred or advantageous over other embodiments or designs (and such term is not intended to connote that such embodiments are necessarily extraordinary or superlative examples). Rather, use of the word “illustrative” is intended to present concepts in a concrete manner. Accordingly, all such modifications are intended to be included within the scope of the present disclosure. Other substitutions, modifications, changes, and omissions may be made in the design, operating conditions, and arrangement of the preferred and other illustrative embodiments without departing from the scope of the appended claims.

As used herein, “about” will be understood by persons of ordinary skill in the art and will vary to some extent depending upon the context in which it is used. If there are uses of the term which are not clear to persons of ordinary skill in the art, given the context in which it is used, “about” will mean up to plus or minus 10% of the particular term.

The use of the terms “a” and “an” and “the” and similar referents in the context of describing the elements (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein, and each separate value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g., “such as”) provided herein, is intended merely to better illuminate the embodiments and does not pose a limitation on the scope of the claims unless otherwise stated. No language in the specification should be construed as indicating any non-claimed element as essential.

While certain embodiments have been illustrated and described, it should be understood that changes and modifications can be made therein in accordance with ordinary skill in the art without departing from the technology in its broader aspects as defined in the following claims.

The embodiments, illustratively described herein may suitably be practiced in the absence of any element or elements, limitation or limitations, not specifically disclosed herein. Thus, for example, the terms “comprising,” “including,” “containing,” etc. shall be read expansively and without limitation. Additionally, the terms and expressions employed herein have been used as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding any equivalents of the features shown and described or portions thereof, but it is recognized that various modifications are possible within the scope of the claimed technology. Additionally, the phrase “consisting essentially of” will be understood to include those elements specifically recited and those additional elements that do not materially affect the basic and novel characteristics of the claimed technology. The phrase “consisting of” excludes any element not specified.

The present disclosure is not to be limited in terms of the particular embodiments described in this application. Many modifications and variations can be made without departing from its spirit and scope, as will be apparent to those skilled in the art. Functionally equivalent methods and compositions within the scope of the disclosure, in addition to those enumerated herein, will be apparent to those skilled in the art from the foregoing descriptions. Such modifications and variations are intended to fall within the scope of the appended claims. The present disclosure is to be limited only by the terms of the appended claims, along with the full scope of equivalents to which such claims are entitled. It is to be understood that this disclosure is not limited to particular methods, reagents, compounds compositions or biological systems, which can of course vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting.

As will be understood by one skilled in the art, for any and all purposes, particularly in terms of providing a written description, all ranges disclosed herein also encompass any and all possible subranges and combinations of subranges thereof. Any listed range can be easily recognized as sufficiently describing and enabling the same range being broken down into at least equal halves, thirds, quarters, fifths, tenths, etc. As a non-limiting example, each range discussed herein can be readily broken down into a lower third, middle third and upper third, etc. As will also be understood by one skilled in the art all language such as “up to,” “at least,” “greater than,” “less than,” and the like, include the number recited and refer to ranges which can be subsequently broken down into subranges as discussed above. Finally, as will be understood by one skilled in the art, a range includes each individual member.

All publications, patent applications, issued patents, and other documents referred to in this specification are herein incorporated by reference as if each individual publication, patent application, issued patent, or other document was specifically and individually indicated to be incorporated by reference in its entirety. Definitions that are contained in text incorporated by reference are excluded to the extent that they contradict definitions in this disclosure.

Other substitutions, modifications, changes and omissions may also be made in the design, operating conditions and arrangement of the various illustrative embodiments without departing from the scope of the present invention. For example, any element disclosed in one embodiment may be incorporated or utilized with any other embodiment disclosed herein. Also, for example, the order or sequence of any process or method steps may be varied or re-sequenced according to alternative embodiments. Any means-plus-function clause is intended to cover the structures described herein as performing the recited function and not only structural equivalents but also equivalent structures. Other substitutions, modifications, changes and omissions may be made in the design, operating configuration, and arrangement of the preferred and other illustrative embodiments without departing from the scope of the appended claims. 

What is claimed is:
 1. A process for upgrading a solid carbonaceous material, comprising: heating the solid carbonaceous material in the presence of a catalyst under partial pyrolysis conditions, and obtaining an upgraded solid carbonaceous product, a gaseous product, and a spent catalyst.
 2. The process of claim 1, wherein the solid carbonaceous material is coal and the upgraded solid carbonaceous product is an upgraded coal product.
 3. The process of claim 1, wherein a weight of fixed carbon retained in the upgraded solid carbonaceous product is at least 50 weight percent of fixed carbon in the solid carbonaceous material.
 4. The process of claim 1, wherein a weight of ash retained in the upgraded solid carbonaceous product is at least 60 weight percent of ash in the solid carbonaceous material.
 5. The process of claim 2, wherein a weight of ash retained in the upgraded coal product is at least 60 weight percent of ash in the coal.
 6. The process of claim 1, wherein a weight of volatile matter retained in the upgraded solid carbonaceous product is from about 10 to about 90 weight percent of volatile matter in the solid carbonaceous material.
 7. The process of claim 2, wherein a weight of volatile matter retained in the upgraded coal product is from about 10 to about 90 weight percent of volatile matter in the coal.
 8. The process of claim 1, further comprising pretreating the starting solid carbonaceous material prior to heating under partial pyrolysis conditions using at least one of a dryer, a de-asher, and a washer.
 9. The process of claim 1, further comprising obtaining an amount of CO₂ greater than about 10 weight % of the volatile matter in the starting solid carbonaceous material.
 10. The process of claim 1, further comprising separating the gaseous product from the upgraded solid carbonaceous product.
 11. The process of claim 11, further comprising condensing the separated gaseous product into a gaseous stream and a liquid stream.
 12. The process of claim 11, further comprising compressing the separated gaseous product resulting in a gaseous stream and a liquid stream.
 13. The process of claim 1, further comprising obtaining an amount of a non-condensable fuel gas from about 1 to about 40 weight % of the volatile matter in the starting solid carbonaceous material.
 14. The process of claim 2, further comprising obtaining an amount of a non-condensable fuel gas from about 1 to about 40 weight % of the volatile matter in the starting coal.
 15. The process of claim 1, further comprising obtaining an amount of LPG greater than from about 1 to about 40 weight % of the volatile matter in the starting solid carbonaceous material.
 16. The process of claim 2, further comprising obtaining an amount of LPG greater than from about 1 to about 40 weight % of the volatile matter in the starting coal.
 17. The process of claim 1, further comprising obtaining an amount of BTEX from about 0.5 to about 40 weight % of the volatile matter in the starting solid carbonaceous material.
 18. The process of claim 2, further comprising obtaining an amount of BTEX from about 0.5 to about 40 weight % of the volatile matter in the starting coal.
 19. The process of claim 1, further comprising obtaining an amount of Higher Hydrocarbons from about 0.3 to about 20 weight % of the volatile matter in the starting solid carbonaceous material.
 20. The process of claim 2, further comprising obtaining an amount of Higher Hydrocarbons from about 0.3 to about 20 weight % of the volatile matter in the starting coal.
 21. The process of claim 1, further comprising obtaining an amount of heteroatom-containing organics that is no greater than 5 weight % of the volatile matter in the starting solid carbonaceous material.
 22. The process of claim 2, further comprising obtaining an amount of heteroatom-containing organics that is no greater than 5 weight % of the volatile matter in the starting coal.
 23. The process of claim 1, wherein the spent catalyst and the upgraded solid carbonaceous product are recovered as a mixture.
 24. The process of claim 2, wherein the spent catalyst and the upgraded solid coal are recovered as a mixture.
 25. The process of claim 1, wherein the spent catalyst and the upgraded solid carbonaceous product are recovered separately.
 26. The process of claim 26, further comprising regenerating the spent catalyst by contacting the spent catalyst with a mixture of gases containing at least one oxidizing gas to form a regenerated catalyst.
 27. The process of claim 27, wherein at least a portion of the regenerated catalyst is heated in the presence of additional solid carbonaceous material in a subsequent partial pyrolysis reaction.
 28. The process of claim 26, further comprising regenerating the spent catalyst by acid washing the spent catalyst with an acidic solution to form a regenerated catalyst.
 29. The process of claim 29, wherein at least a portion of the regenerated catalyst is heated in the presence of additional solid carbonaceous material in a subsequent partial pyrolysis reaction.
 30. The process of claim 1, wherein a weight of total sulfur retained in the upgraded solid carbonaceous product is no more than 80 weight percent of the total sulfur in the starting solid carbonaceous material.
 31. The process of claim 1, wherein a weight of organic sulfur retained in the upgraded solid carbonaceous product is no more than 50 weight percent of the organic sulfur in the starting solid carbonaceous material.
 32. The process of claim 1, wherein a weight of sulfates retained in the upgraded solid carbonaceous product is no more than 50 weight percent of sulfates in the starting solid carbonaceous material.
 33. A process for converting a solid carbonaceous material in a beneficiation system into a upgraded solid carbonaceous product, the process comprising: introducing the solid carbonaceous material and a catalyst into a pyrolysis reactor to produce a gaseous product stream and a solid product stream, wherein the solid product stream comprises the upgraded solid carbonaceous product; recovering the gaseous product stream from the reactor; and recovering the solid product stream from the reactor.
 34. The process of claim 34, wherein the solid carbonaceous material is coal and the upgraded solid carbonaceous product is an upgraded coal product.
 35. The process of claim 34, wherein the catalyst is immobilized in the pyrolysis reactor; and the process further comprises separating the upgraded solid carbonaceous product from the catalyst inside the pyrolysis reactor.
 36. The process of claim 36, further comprising: recovering a separated spent catalyst from the pyrolysis reactor; transferring the spent catalyst to a regenerator; and regenerating the spent catalyst in the regenerator, in which unpyrolyzed coal, coke, and carbonaceous material are removed from the spent catalyst.
 37. The process of claim 36, further comprising: transferring the gaseous product stream to a separator; and at least partially condensing the gaseous product stream in the separator producing a refined gas stream, a hydrocarbon liquid stream, and an aqueous liquid phase stream.
 38. The process of claim 34, wherein the solid product stream further comprises a spent catalyst, the process further comprising: separating the solid product stream into the upgraded solid carbonaceous product and the spent catalyst after recovering the solid product stream from the pyrolysis reactor, wherein the separated spent catalyst comprises the catalyst and at least one of unpyrolyzed coal, coke, and carbonaceous material.
 39. The process of claim 39, further comprising: transferring the separated catalyst to a regenerator in which at least a portion of the at least one of the unpyrolyzed coal, coke, and carbonaceous material is removed from the catalyst; and transferring the gaseous product stream to a separator in which the gaseous product stream is at least partially condensed in the separator producing a refined gas stream, a hydrocarbon liquid stream, and an aqueous liquid phase stream.
 40. The process of claim 40, wherein at least a portion of the at least one of the unpyrolyzed coal, coke, and carbonaceous material is removed from the catalyst by at least one of combustion, steam, and a reducing gas.
 41. The process of claim 39, wherein the pyrolysis reactor is configured as one of a HERB, a fluidized bed, a moving bed, or an entrained flow bed, and wherein the coal and the catalyst move through the pyrolysis reactor.
 42. The process of claim 39, wherein the solid product stream is transferred outside the pyrolysis reactor to a solid-solid separator that separates the upgraded solid carbonaceous product and the spent catalyst.
 43. The process of claim 39, wherein the solid-solid separator includes a classifier that separates the upgraded solid carbonaceous product from the spent catalyst based on one of particle size, mass, or density.
 44. The process of claim 44, wherein at least one of a size and a density of the spent catalyst is different than at least one of a size and a density of the upgraded solid carbonaceous product, and wherein the classifier of the solid-solid separator separates the upgraded solid carbonaceous product and the spent catalyst based on at least one of size and density.
 45. The process of claim 34, further comprising: reducing a size of the particles of the solid carbonaceous material in a pulverizer prior to being introduced into the pyrolysis reactor; and pretreating the solid carbonaceous material in a pretreating device that includes at least one of a dryer configured to dry the coal from the pulverizer utilizing a stream of heated fluid, a washer configured to wash the coal from the pulverizer, and a de-asher configured to remove ash from the coal, wherein the pretreating device is provided between the pulverizer and the pyrolysis reactor.
 46. The process of claim 46, wherein the stream of heated fluid is hot flue gas produced by a regenerator during removal of at least a portion of any unpyrolyzed coal, coke, and carbonaceous material from the spent catalyst utilizing an oxygen-carrying gas.
 47. The process of claim 40, wherein the separator further includes an acid gas removal system that separates at least one of a sulfur-carrying compound, a nitrogen-carrying compound, and carbon dioxide from the gaseous product stream.
 48. The process of claim 34, wherein the catalyst introduced into the pyrolysis reactor includes a first portion comprising regenerated catalyst received from a regenerator and a second portion comprising new catalyst that has not been regenerated, and wherein the first portion of regenerated catalyst has a higher relative temperature than the new catalyst and the coal, such that the regenerated catalyst is a heating medium to heat the coal introduced into the pyrolysis reactor.
 49. The process of claim 34, wherein the catalytic pyrolysis of the solid carbonaceous material takes place at a temperature from about 350° C. to about 850° C.
 50. The process of claim 50, wherein the solid carbonaceous material introduced into the pyrolysis reactor has a weighted hour space velocity from about 0.2 to about 25 kg/hr per kg of catalyst.
 51. The process of claim 50, wherein the solid carbonaceous material has a residence time during the catalytic process from about 0.1 second to about 1 minute.
 52. The process of claim 34, wherein a weight ratio of the catalyst to solid carbonaceous material introduced into the pyrolysis reactor is from about 0 to about
 100. 53. The process of claim 34, further comprising: providing an acid gas removal system that is configured to capture and isolating CO₂ from at least one of the gaseous product from the pyrolysis reactor and a gas from a regenerator configured to regenerate spent catalyst from the pyrolysis reactor; and obtaining an amount of CO₂ greater than about 4 weight % of the dry ash free coal.
 54. The process of claim 34, further comprising obtaining an amount of CO₂ greater than about 10 weight % of the volatile matter in the starting solid carbonaceous material.
 55. The process of claim 34, further comprising obtaining an amount of CO₂ greater than about 4 weight % of the dry ash free coal.
 56. The process of claim 34, further comprising: regenerating a spent catalyst in a regenerator configured to produce a hot flue gas during regeneration; and transferring at least a portion of the hot flue gas to the pyrolysis reactor to fluidize the pyrolysis reactor.
 57. The process of claim 57, wherein a gaseous fluid comprising at least one of CO, CO₂, water, hydrogen, and oxygen is introduced into the regenerator to facilitate removal of unpyrolyzed coal, coke, and carbonaceous material from the spent catalyst.
 58. The process of claim 58, further comprising collecting the hot flue gas that includes CO₂ for one of carbon sequestration or enhanced oil recovery.
 59. The process of claim 58, further comprising passing the hot flue gas through a heat exchanger to produce heat that is used to heat the solid carbonaceous material in the pyrolysis reactor.
 60. The process of claim 57, wherein the regenerator uses steam in addition to, or instead of, air to remove the coal, coke, and carbonaceous material from the spent catalyst by at least one of hydrolysis and steam gasification.
 61. The process of claim 57, wherein the regenerator uses hydrogen or at least one other hydrogen-containing chemical, including hydrocarbons, to reductively remove the coal, coke, and carbonaceous material from the spent catalyst.
 62. The process of claim 34, wherein a gas is co-fed into the pyrolysis reactor, wherein the gas comprises at least one light hydrocarbon compound that is recovered from the gaseous product stream.
 63. The process of claim 63, wherein the at least one light hydrocarbon compound is recycled back to the pyrolysis reactor.
 64. The process of claim 63, further comprising obtaining an amount of BTEX from about 0.5 to about 80 weight % of the volatile matter in the starting solid carbonaceous material.
 65. The process of claim 34, wherein a biomass is co-fed into the pyrolysis reactor.
 66. The process of claim 34, wherein at least one of an oil shale, a coal derived liquid, a tar sand, and a petroleum is co-fed into the pyrolysis reactor.
 67. The process of claim 34, wherein at least one of a wet gas and a natural gas is co-fed into the pyrolysis reactor.
 68. The process of claim 34, wherein the pyrolysis reactor includes a stationary catalyst, such that the solid carbonaceous material moves relative to the catalyst through the reactor, to produce the gaseous product stream and the solid product stream, the process further comprising: transferring the gaseous product stream to a separator to at least partially condense at least a portion of the gas product stream into a liquid product and a gaseous product; and wherein the solid product stream contains less than 1 weight part catalyst per 100 parts upgraded carbonaceous product.
 69. A process for converting a biomass in a beneficiation system into an upgraded solid product, the process comprising: introducing the biomass and a catalyst into a pyrolysis reactor to produce a gaseous product stream and an upgraded solid product stream, the solid product stream comprising spent catalyst and the upgraded solid product; separating the upgraded solid product and the spent catalyst; transferring the separated spent catalyst to a regenerator that removes at least a portion of any unpyrolyzed coal, coke, and other carbonaceous material from the spent catalyst; and transferring the gaseous product stream to a separator that produces a liquid product and a gaseous product; wherein a weight of ash retained in the upgraded solid product is at least 60 weight percent of ash in the biomass introduced into the pyrolysis reactor
 70. The process of claim 1, wherein an amount of phenol produced is less than an amount of toluene produced on a weight basis.
 71. The process of claim 1, wherein an amount of tars produced is less than an amount of light oils produced on a weight basis. 